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EX-32.2 - EX-32.2 - Western Refining, Inc.d79876exv32w2.htm
EX-23.1 - EX-23.1 - Western Refining, Inc.d79876exv23w1.htm
EX-31.1 - EX-31.1 - Western Refining, Inc.d79876exv31w1.htm
EX-32.1 - EX-32.1 - Western Refining, Inc.d79876exv32w1.htm
EX-12.1 - EX-12.1 - Western Refining, Inc.d79876exv12w1.htm
EX-31.2 - EX-31.2 - Western Refining, Inc.d79876exv31w2.htm
EX-10.32 - EX-10.32 - Western Refining, Inc.d79876exv10w32.htm
EX-10.33 - EX-10.33 - Western Refining, Inc.d79876exv10w33.htm
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Fiscal Year Ended December 31, 2010
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from            to           
 
Commission File Number: 001-32721
 
WESTERN REFINING, INC.
(Exact name of registrant as specified in its charter)
 
     
Delaware   20-3472415
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
123 W. Mills Ave., Suite 200
El Paso, Texas
(Address of principal executive offices)
  79901
(Zip Code)
 
Registrant’s telephone number, including area code:
(915) 534-1400
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to rule 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large Accelerated Filer o     Accelerated Filer þ
 
Non-Accelerated Filer o (Do not check if a smaller reporting company) Smaller Reporting Company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2010 (the last business day of the registrant’s most recently completed second fiscal quarter) was $269,651,530.
 
As of February 25, 2011, there were 90,805,490 shares outstanding, par value $0.01, of the registrant’s common stock.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive proxy statement for the registrant’s 2011 annual meeting of stockholders are incorporated by reference into Part III of this report.
 


 

 
WESTERN REFINING, INC. AND SUBSIDIARIES
 
INDEX
 
             
  Business     3  
  Risk Factors     17  
  Unresolved Staff Comments     27  
  Properties     27  
  Legal Proceedings     27  
  Reserved     27  
 
PART II
  Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities     27  
  Selected Financial Data     30  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     33  
  Quantitative and Qualitative Disclosure About Market Risk     69  
  Financial Statements and Supplementary Data     73  
  Changes In and Disagreements With Accountants on Accounting and Financial Disclosure     125  
  Controls and Procedures     125  
  Other Information     125  
 
PART III
  Directors, Executive Officers, and Corporate Governance     125  
  Executive Compensation     125  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     125  
  Certain Relationships and Related Transactions, and Director Independence     126  
  Principal Accountant Fees and Services     126  
 
PART IV
  Exhibits and Financial Statement Schedules     126  
    132  
 EX-10.32
 EX-10.33
 EX-12.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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Forward-Looking Statements
 
As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Annual Report on Form 10-K, and in particular under the sections entitled Item 1. Business, Item 3. Legal Proceedings, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. These forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, including our expected timeframe for restarting refining operations at our Yorktown refinery, margins, profitability, deferred taxes, capital expenditures, liquidity and capital resources, our working capital requirements, our ability to improve our capital structure through asset sales and/or through certain financings, and other financial and operating information. Forward-looking statements also include those regarding the recommencing of refining operations at our Yorktown facility, the timing of completion of certain operational improvements we are making at our refineries, future operational or refinery efficiencies and cost savings, future refining capacity, timing of future maintenance turnarounds, the amount or sufficiency of future cash flows and earnings growth, future expenditures and future contributions related to pension and postretirement obligations, our ability to manage our inventory price exposure through commodity derivative instruments, the impact on our business of existing and future state and federal regulatory requirements, environmental loss contingency accruals, projected remediation costs or requirements, and the expected outcomes of legal proceedings in which we are involved. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future,” and similar terms and phrases to identify forward-looking statements in this report.
 
Forward-looking statements reflect our current expectations regarding future events, results, or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations, and cash flows.
 
Actual events, results, and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
 
  •  worsening of the economic downturn and instability and volatility in the financial markets;
 
  •  changes in the underlying demand for our refined products;
 
  •  availability, costs, and price volatility of crude oil, other refinery feedstocks, and refined products;
 
  •  availability of renewable fuels for blending and Renewal Identification Numbers, or RINs, to meet Renewable Fuel Standards, or RFS, obligations;
 
  •  changes in crack spreads;
 
  •  changes in the spread between West Texas Intermediate, or WTI, crude oil and West Texas Sour, or WTS, crude oil, also known as the sweet/sour spread;
 
  •  changes in the spread between WTI crude oil and Maya crude oil, also known as the light/heavy spread;
 
  •  changes in the spread between WTI crude oil and Dated Brent crude oil;
 
  •  adverse changes in the credit ratings assigned to our debt instruments;
 
  •  conditions in the capital markets;
 
  •  construction of new, or expansion of existing product pipelines in the areas that we serve;
 
  •  actions of customers and competitors;
 
  •  changes in fuel and utility costs incurred by our refineries;
 
  •  the effect of weather-related problems on our operations;


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  •  disruptions due to equipment interruption, pipeline disruptions, or failure at our or third-party facilities;
 
  •  execution of planned capital projects, cost overruns relating to those projects, and failure to realize the expected benefits from those projects;
 
  •  effects of, and costs relating to compliance with current and future local, state, and federal environmental, economic, climate change, safety, tax and other laws, policies and regulations, and enforcement initiatives;
 
  •  rulings, judgments or settlements in litigation, or other legal or regulatory matters, including unexpected environmental remediation costs in excess of any reserves or insurance coverage;
 
  •  the price, availability, and acceptance of alternative fuels and alternative fuel vehicles;
 
  •  operating hazards, natural disasters, casualty losses, acts of terrorism, and other matters beyond our control; and
 
  •  other factors discussed in more detail under Part 1. — Item 1A. Risk Factors of this report, which are incorporated herein by this reference.
 
Any one of these factors or a combination of these factors could materially affect our results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. You are urged to consider these factors carefully in evaluating any forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements.
 
Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can provide no assurance that such plans, intentions, or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. The forward-looking statements included herein are made only as of the date of this report, and we are not required to update any information to reflect events or circumstances that may occur after the date of this report, except as required by applicable law.


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PART I
 
In this Annual Report on Form 10-K, all references to “Western Refining,” “the Company,” “Western,” “we,” “us,” and “our” refer to Western Refining, Inc., or WNR, and the entities that became its subsidiaries upon closing of our initial public offering (including Western Refining Company, L.P., or Western Refining LP), and Giant Industries, Inc., or Giant, and its subsidiaries, which became wholly-owned subsidiaries on May 31, 2007, unless the context otherwise requires or where otherwise indicated. Any references to the “Company” prior to this date exclude the operations of Giant.
 
Item 1.   Business
 
Overview
 
We are an independent crude oil refiner and marketer of refined products and also operate service stations and convenience stores. We own and operate two refineries with a total crude oil throughput capacity of approximately 151,000 barrels per day, or bpd. In addition to our 128,000 bpd refinery in El Paso, Texas, we also own and operate a 23,000 bpd refinery near Gallup, New Mexico. Until September 2010, we operated a 70,000 bpd refinery near Yorktown, Virginia, and until November 2009, we operated a 17,000 bpd refinery near Bloomfield, New Mexico. We temporarily suspended refining operations at our Yorktown facility in September 2010 and indefinitely suspended refining operations at the Bloomfield refinery in November 2009. We continue to operate Yorktown and Bloomfield as product distribution terminals and supply our refined products to those areas. Our primary operating areas encompass West Texas, Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic region. In addition to the refineries, we also own and operate stand-alone refined product distribution terminals in Albuquerque, New Mexico; Yorktown; and Bloomfield; as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. At February 25, 2011, we also own and operate 150 retail service stations and convenience stores in Arizona, Colorado, and New Mexico; a fleet of crude oil and refined product truck transports; and a wholesale petroleum products distributor that operates in Arizona, California, Colorado, Nevada, New Mexico, Texas, and Utah.
 
We were incorporated in September 2005 under Delaware law. In January 2006, we completed an initial public offering and our stock began trading on the New York Stock Exchange, or NYSE, under the symbol “WNR.” Our principal offices are located in El Paso, Texas.
 
On May 31, 2007, we completed the acquisition of Giant. Under the terms of the merger agreement, we acquired 100% of Giant’s 14,639,312 outstanding shares for $77.00 per share in cash for a total purchase price of $1,149.2 million, funded primarily through a $1,125.0 million secured term loan. In connection with the acquisition, we borrowed an additional $275.0 million in July 2007, when we paid off and retired Giant’s 8% and 11% Senior Subordinated Notes. Prior to the acquisition of Giant, we generated substantially all of our revenues from our refining operations in El Paso. With the acquisition of Giant, we also gained a diverse mix of complementary retail and wholesale businesses.
 
Following the acquisition of Giant, we began reporting our operating results in three business segments: the refining group, the wholesale group, and the retail group. Our refining group operates the two refineries and related refined product distribution terminals and asphalt terminals. At the refineries, we refine crude oil and other feedstocks into finished products such as gasoline, diesel fuel, jet fuel, and asphalt. Our refineries market finished products to a diverse customer base including wholesale distributors and retail chains. Our wholesale group distributes gasoline, diesel fuel, and lubricant products. Our retail group operates service stations and convenience stores and sells gasoline, diesel fuel, and merchandise. See Note 3, Segment Information, in the Notes to Consolidated Financial Statements included in this annual report for detailed information on our operating results by segment.
 
Refining Segment
 
Our refining group currently operates two refineries: one in El Paso, Texas (the El Paso refinery), and one near Gallup, New Mexico (the Gallup refinery). Both of our refineries have their own refined product distribution terminals. In addition, we operate three stand-alone refined product distribution terminals in Albuquerque, New


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Mexico; Yorktown, Virginia; and Bloomfield, New Mexico. Our refining group operates a crude oil gathering pipeline system in the Four Corners region of New Mexico and a Company-owned pipeline that runs from Southeast to Northwest New Mexico, or Texas-New Mexico pipeline. The pipeline can transport crude oil from Southeast New Mexico to the Four Corners region and south from Lynch, New Mexico to Jal, New Mexico. We do not currently transport crude via pipeline from Southeast New Mexico. We presently use sections of the pipeline to deliver crude oil to our Gallup refinery and to transport crude oil for unrelated third parties. This pipeline provides us with an alternative method of transportation within New Mexico and an alternative supply of crude oil for our Gallup refinery. Our refining operations also include an asphalt plant in El Paso and four asphalt terminals in El Paso, Phoenix, Tucson, and Albuquerque.
 
In September 2010, due to the continued effect of unfavorable economic conditions in the refining market, especially in the Mid-Atlantic region, and the resulting financial performance of our Yorktown refinery, we temporarily suspended refining operations at the Yorktown facility and will operate Yorktown as a refined products distribution terminal to supply refined products to the region in the near term. We anticipate restarting refining operations in Yorktown during 2013. We will continue to monitor our Yorktown long-lived assets, both operating and idled, and capital projects for potential asset impairments or project write-offs until conditions improve. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus affecting our earnings. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Long-lived Assets.
 
Until November 2009, our operations in Bloomfield included both crude oil refining and product distribution. During the fourth quarter of 2009, we decided to consolidate the refining operations of the Gallup and Bloomfield refineries into a single operation at the Gallup refinery to eliminate certain operating costs while maintaining the capability to process approximately the same volumes of crude that we had previously processed through the two refineries. We continue to supply refined products to the Four Corners area through ongoing operations at the Bloomfield product distribution terminal, and by utilizing a recent pipeline connection and long-term exchange supply agreement. Through the long-term exchange agreement, we supply barrels to the Bloomfield product distribution terminal in exchange for barrels produced at the El Paso refinery. In the latter part of the fourth quarter of 2009, as a result of the indefinite suspension of refining activities at the Bloomfield refinery, we recorded a non-cash asset impairment charge of $52.8 million and incurred approximately $2.2 million in other costs primarily related to employee severance programs for the Bloomfield refinery. During the fourth quarter of 2010, we performed an analysis of specific assets that we had previously planned to relocate from our Bloomfield facility to our Gallup refinery. As a result of this analysis, we recorded an additional non-cash impairment charge of $9.1 million. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Major Influences on Results of Operations — Long-lived Asset Impairment Loss.
 
Principal Products.  Our refineries make various grades of gasoline, diesel fuel, jet fuel, and other products from crude oil, other feedstocks, and blending components. We also acquire finished products through exchange agreements and from various third-party suppliers. We sell these products through our own wholesale group and service stations, independent wholesalers and retailers, commercial accounts, and sales and exchanges with major oil companies. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for detail on production by refinery. The following table summarizes sales percentage by product for the years indicated:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Gasoline
    54.0 %     57.2 %     48.9 %
Diesel fuel
    32.3       30.2       38.6  
Jet fuel
    5.6       4.6       5.1  
Asphalt
    2.5       2.7       1.9  
Other
    5.6       5.3       5.5  
                         
Total sales percentage by type
    100.0 %     100.0 %     100.0 %
                         


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Customers.  We sell a variety of refined products to our diverse customer base. No single customer accounted for more than 10% of our consolidated net sales for 2010.
 
All of our refining sales were domestic sales in the United States, except for sales of gasoline and diesel fuel for export into Juarez, Mexico. The sales for export were to PMI Trading Limited, an affiliate of Petroleos Mexicanos, the Mexican state-owned oil company, and accounted for approximately 8.3%, 8.5%, and 8.3% of our consolidated net sales during the years ended December 31, 2010, 2009, and 2008, respectively.
 
We also purchase additional refined products from third parties to supplement supply to our customers. These products are similar to the products that we currently manufacture.
 
Competition.  We operate primarily in West Texas, Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic region. We supply refined products to these areas from our refineries, from other refineries in these regions, and from refineries located in other regions via interstate pipelines. These areas have substantial refining capacity, and we also compete with offshore refiners that deliver product by water transport.
 
Petroleum refining and marketing is highly competitive. The principal competitive factors affecting us are costs of crude oil and other feedstocks, refinery efficiency, operating costs, refinery product mix, and costs of product distribution and transportation. Due to their geographic diversity, larger and more complex refineries, integrated operations, and greater resources, some of our competitors may be better able to withstand volatile market conditions, compete on the basis of price, obtain crude oil in times of shortage, and bear the economic risk inherent in all phases of the refining industry.
 
In the Southwest, the El Paso and Gallup refineries primarily compete with Valero Energy Corp., ConocoPhillips Company, Alon USA Energy, Inc., Holly Corporation, Tesoro Corporation, Chevron Products Company, or Chevron, and Suncor Energy, Inc. as well as refineries in other regions of the country that serve the regions we serve through pipelines.
 
The areas where we sell refined products are also supplied by various refined product pipelines. Any expansions or additional product supplied by these third-party pipelines could put downward pressure on refined product prices in these areas.
 
When in operation as a refinery, our Yorktown facility in the Mid-Atlantic region primarily competed with Sunoco, Inc., Valero Energy Corp., ConocoPhillips Company, Hess Corporation, and other refineries in the Gulf Coast via the Colonial Pipeline that runs from the Gulf Coast area to New Jersey. We also competed with offshore refiners that deliver product by water transport to the region.
 
To the extent that climate change legislation is passed, imposing greenhouse gas restrictions on domestic refiners, all domestic refiners will be at a competitive disadvantage to offshore refineries. In November 2010, the State of New Mexico adopted regulations allowing New Mexico to participate in a regional greenhouse cap-and-trade program through the Western Climate Initiative. The regulation becomes effective in 2012 unless the current New Mexico administration reverses the regulations or postpones the effective date. Our Gallup refinery, along with other industrial facilities in New Mexico, will be required to reduce their greenhouse gas emissions by 2% per year between 2012 and 2020, or obtain emission credits from other regulated facilities. The program will not be initiated unless 100 million tons of emissions are available regionally.
 
Southwest
 
El Paso Refinery
 
Our El Paso refinery has a crude oil throughput capacity of 128,000 bpd with approximately 4.3 million barrels of storage capacity, a finished product terminal, and an asphalt plant and terminal.
 
This refinery is well situated to serve two separate geographic areas, allowing us a diversified market pricing exposure. Tucson and Phoenix typically reflect a West Coast market pricing structure, while El Paso, Albuquerque, and Juarez, Mexico typically reflect a Gulf Coast market pricing structure.
 
Process Summary.  Our El Paso refinery is a nominal 128,000 bpd crude oil throughput cracking facility that has historically run a high percentage of WTI crude oil to optimize the yields of higher value refined products that


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currently account for over 90% of our production output. With the completion of our gasoline desulfurization project in May 2009 we have the flexibility to process up to 22% WTS crude oil, which typically is less expensive than WTI crude oil.
 
Under a sulfuric acid regeneration and sulfur gas processing agreement with E.I. du Pont de Nemours, or DuPont, Western Refining LP has a long-term commitment to purchase services for use by its El Paso refinery. In exchange for this commitment, DuPont agreed to design, construct, and operate two sulfuric acid regeneration plants on property we lease to DuPont within our El Paso refinery. In November 2008, we began processing all sulfur gas from the north side of the El Paso refinery at the DuPont facility. In January 2009, we began processing all sulfur gas from the south side of the El Paso refinery at the DuPont facility.
 
Power Supply.  Electricity is supplied to our refinery by a regional electric company via two separate feeders to both the north and south sides of our refinery. We have an electrical power curtailment plan to conserve power in the event of a partial outage.
 
Natural gas is supplied to our refinery via pipeline under two transportation agreements. One transportation agreement is on an interruptible basis while the other is on an uninterruptible basis. We purchase our natural gas at market rates or under fixed-price agreements.
 
Raw Material Supply.  The primary inputs for our refinery consist of crude oil, isobutane, and alkylate. Operation of our gasoline desulfurization unit since startup in May 2009 has allowed for higher sour rates. Currently, we have the capability to process up to 22% of WTS crude oil at the El Paso refinery. Smaller projects that we have deferred will allow us to incrementally increase our WTS crude oil processing capability at the El Paso refinery. The following table summarizes the historical feedstocks used by our El Paso refinery for the years indicated:
 
                                 
                      Percentage For
 
                      Year Ended
 
Refinery Feedstocks
  Year Ended December 31,     December 31,
 
(bpd)
  2010     2009     2008     2010  
 
Crude Oils:
                               
Sweet crude oil
    104,119       99,680       100,130       81.9 %
Sour crude oil
    14,007       17,601       16,985       11.0  
                                 
Total Crude Oils
    118,126       117,281       117,115       92.9  
                                 
Other Feedstocks and Blendstocks:
                               
Intermediates and other
    4,359       3,611       4,302       3.4  
Blendstocks
    4,692       5,573       5,152       3.7  
                                 
Total Other Feedstocks and Blendstocks
    9,051       9,184       9,454       7.1  
                                 
Total Crude Oils and Other Feedstocks and Blendstocks
    127,177       126,465       126,569       100.0 %
                                 
 
Crude oil is delivered to our El Paso refinery via a 450-mile crude oil pipeline owned and operated by Kinder Morgan under a 30-year crude oil transportation agreement that began in 2004. The system handles both WTI and WTS crude oil with its main trunkline into El Paso used solely for the supply of crude oil to us on a published tariff. The crude oil pipeline has access to the majority of the producing fields in the Permian Basin, which gives us access to a plentiful supply of WTI and WTS crude oil from fields with long reserve lives. We generally buy our crude oil under contracts with various crude oil providers, including a contract with Kinder Morgan that expires in 2020 and shorter term contracts with other suppliers, at market-based rates.
 
We also have access to blendstocks and refined products from the Gulf Coast through a pipeline that runs from the Gulf Coast to El Paso.
 
Refined Products Transportation.  Outside of the El Paso area, which is supplied via our El Paso refinery product distribution terminal, we provide refined products to other areas, including Tucson, Phoenix, Albuquerque, and Juarez, Mexico. Supply to these areas is achieved through pipeline systems that are linked to our refinery. Our refined products are delivered to Tucson and Phoenix through the Kinder Morgan East Line, which was expanded to


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over 200,000 bpd in the fourth quarter of 2007, and to Albuquerque and Juarez, Mexico through pipelines owned by Plains All American Pipeline L.P., or Plains. We also sell our refined products at our product distribution terminal and rail loading facilities in El Paso. Another pipeline owned by Kinder Morgan provides diesel fuel to the Union Pacific railway in El Paso.
 
Both Kinder Morgan’s East Line and the Plains pipeline to Albuquerque are interstate pipelines regulated by the Federal Energy Regulatory Commission, or FERC. The tariff provisions for these pipelines include prorating policies that grant historical shippers line space that is consistent with their prior activities as well as a prorated portion of any expansions.
 
Four Corners Refineries
 
Our refining group operates a refinery near Gallup, New Mexico. Our Gallup refinery has a crude oil throughput capacity of 23,000 bpd. Until November 2009, we also operated a refinery near Bloomfield, New Mexico. Our Bloomfield refinery had a crude oil throughput capacity of 17,000 bpd. We typically had not operated these refineries at full capacity, and in November 2009, we indefinitely suspended refining operations at Bloomfield. Our Bloomfield facility currently operates as a product distribution terminal. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Major Influences on Results of Operations — Long-lived Asset Impairment Loss. We market refined products from the Gallup refinery primarily in Arizona, Colorado, New Mexico, and Utah. Our primary supply of crude oil and natural gas liquids comes from Colorado, New Mexico, and Utah.
 
Process Summary.  The Gallup refinery produces a high percentage of high value products. Each barrel of raw materials processed by our Gallup refinery has resulted in approximately 90% of high value finished products, including gasoline and diesel fuel during the past four years.
 
Power Supply.  Electrical power is supplied to the Gallup refinery by a regional electric cooperative. There are several uninterruptible power supply units throughout the plant to maintain computers and controls in the event of a power outage. Natural gas is supplied to our refinery via two different pipelines. We purchase our natural gas at market rates.
 
Raw Material Supply.  The feedstock for our Gallup refinery is Four Corners Sweet, which comes from the Four Corners area and is delivered by pipelines, including pipelines we own, connected to our refinery and product distribution terminal, or delivered by our trucks to pipeline injection points or refinery tankage. Our pipeline system reaches into the San Juan Basin, located in the Four Corners area, and connects with local common carrier pipelines. We currently own approximately 250 miles of pipeline for delivering crude oil to the refinery.
 
We supplement the crude oil used at our Gallup refinery with other feedstocks. These other feedstocks currently include locally produced natural gas liquids and condensate as well as other feedstocks produced outside of the Four Corners area. Our Gallup refinery is capable of processing approximately 6,000 bpd of natural gas liquids. An adequate supply of natural gas liquids is available for delivery to our Gallup refinery primarily through a 13-mile pipeline we own that connects the refinery to a natural gas liquids processing plant.


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The following table summarizes the historical feedstocks used by our Four Corners refineries for the years indicated:
 
                                 
                      Percentage For
 
                      Year Ended
 
Refinery Feedstocks
  Year Ended December 31,     December 31,
 
(bpd)
  2010     2009(1)     2008     2010  
 
Crude Oil:
                               
Sweet crude oil
    21,140       24,763       28,293       87.6 %
                                 
Total Crude Oil
    21,140       24,763       28,293       87.6  
                                 
Other Feedstocks and Blendstocks:
                               
Intermediates and other
    1,822       1,425       1,077       7.6  
Blendstocks
    1,149       429       1,393       4.8  
                                 
Total Other Feedstocks and Blendstocks
    2,971       1,854       2,470       12.4  
                                 
Total Crude Oil and Other Feedstocks and Blendstocks
    24,111       26,617       30,763       100.0 %
                                 
 
 
(1) Includes barrels processed at our Bloomfield facility through November 2009 when Bloomfield refining operations were indefinitely suspended. We calculated total bpd feedstock volumes by dividing by 365 days.
 
We purchase crude oil from a number of sources, including major oil companies and independent producers, under arrangements that contain market responsive pricing provisions. Many of these arrangements are subject to cancellation by either party or have terms of one year or less. In addition, these arrangements are subject to periodic renegotiation, which could result in our paying higher or lower relative prices for crude oil.
 
Terminal Operations.  Our Gallup refinery has its own product distribution terminal. We own stand-alone finished product terminals in Albuquerque and Bloomfield. The Bloomfield refinery terminal is permitted to operate at 19,000 bpd. This terminal has approximately 251,000 barrels of finished product tankage and a truck loading rack with three loading spots. We utilize a new pipeline connection and a long-term exchange agreement to supply barrels to the Bloomfield refinery terminal. Additionally, there are approximately 470,000 barrels of crude oil and feedstock tankage available for storage for the Gallup refinery. The Albuquerque product distribution terminal is permitted to operate at 27,500 bpd. This terminal has approximately 170,000 barrels of finished product tankage and a truck loading rack with two loading spots. Product deliveries to this terminal are made by truck or by pipeline, including deliveries from our El Paso and Gallup refineries. In the third quarter of 2010, we ceased operating our refined products distribution terminal located in Flagstaff, Arizona. The Flagstaff terminal was permitted to operate at 12,000 bpd. This terminal had approximately 65,000 barrels of finished product tankage and a truck loading rack with three loading spots. Product deliveries to this terminal were made by truck from our Gallup refinery.
 
Refined Products Transportation.  Our Gallup gasoline and diesel fuel production is distributed in Arizona, Colorado, New Mexico, and Utah, primarily via a fleet of finished product trucks operated by our wholesale group.
 
Mid-Atlantic
 
Yorktown Facility
 
In September 2010, we temporarily suspended refining operations at our Yorktown facility due primarily to the continued effect of unfavorable economic conditions in the refining market, especially in the Mid-Atlantic region. Through December 2010, we have been making changes we believe are necessary to operate our Yorktown facility as a stand-alone product distribution terminal in the near term. We currently operate our Yorktown terminal in connection with our sales of refined product in the Yorktown area. We plan to expand our terminal operations at Yorktown to provide terminalling and related services to third parties during 2011.
 
Our Yorktown facility is on Goodwin’s Neck, located on the York River in York County, Virginia. The Yorktown facility has its own deep-water port on the York River, close to the Norfolk military complex and the


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Hampton Roads shipyards. The Yorktown refinery primarily served Yorktown, Virginia; Salisbury, Maryland; Norfolk, Virginia; North Carolina; and the New York Harbor. We anticipate that our product distribution terminal will serve the Mid-Atlantic region.
 
Process Summary.  When operating, our Yorktown refinery is a nominal 70,000 bpd heavy crude oil coking facility that can process a wide variety of crude oil, including certain lower quality crude oils, into high value finished products, including both conventional and reformulated gasoline, ultra low sulfur diesel fuel, and heating oil. We can also produce liquefied petroleum gases, or LPGs, fuel oil, and petroleum coke.
 
Power Supply.  The Yorktown facility electrical power is supplied by the regional electric company via two independent transformers. All process computers and controls are protected by various uninterruptible power supply systems.
 
Natural gas is supplied to our facility via pipeline. The natural gas was used as a back-up to refinery produced fuel gas.
 
Raw Material Supply.  When operating, most of the crude oil for our Yorktown refinery came from South America. Our Yorktown refinery’s strategic location on the York River and its own deep water port access allowed it to receive supply shipments from various regions of the world. The refinery received all of its crude supply from crude oil tankers. Its ability to process a wide range of crude oils allowed our Yorktown refinery to vary its crude oil slate. Lower quality crude oils are typically available at a lower cost compared to higher quality crude oils. The Yorktown refinery also purchased other feedstocks and blendstocks to optimize refinery operations and blending operations.
 
Western Refining Yorktown, Inc., or Western Yorktown, settled a lawsuit with Statoil Marketing & Trading (US) Inc., or Statoil, related to its crude oil supply agreement in February 2010, when the parties mutually agreed to dismiss all claims and counterclaims with prejudice.
 
The following table summarizes the historical feedstocks used by our Yorktown refinery for the years indicated:
 
                                 
                      Percentage For
 
                      Year Ended
 
Refinery Feedstocks
  Year Ended December 31,     December 31,
 
(bpd)
  2010(1)     2009     2008     2010  
 
Crude Oil:
                               
Sweet crude oil
    7,713       1,885       15,291       13.4 %
Heavy crude oil
    40,274       47,659       45,364       69.7  
                                 
Total Crude Oils
    47,987       49,544       60,655       83.1  
                                 
Other Feedstocks and Blendstocks:
                               
Intermediates and other
    4,522       5,398       3,416       7.8  
Blendstocks
    5,255       7,791       5,727       9.1  
                                 
Total Other Feedstocks and Blendstocks
    9,777       13,189       9,143       16.9  
                                 
Total Crude Oils and Other Feedstocks and Blendstocks
    57,764       62,733       69,798       100.0 %
                                 
 
 
(1) Feedstocks for the year ended December 31, 2010 include usage through September 30, 2010. As a result of the temporary suspension of refining operations, we calculated bpd feedstock volumes by dividing total volumes processed by 273 days.
 
Refined Products Transportation.  Most of the finished products sold by the refinery were shipped by barge, with the remaining amount shipped by truck or rail. A rail system that served the refinery transported shipments of mixed butane and petroleum coke from the refinery to our customers.


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Dock System and Storage.  Our facility’s dock system is capable of handling 150,000 ton deadweight tankers and barges up to 200,000 barrels. The facility includes 5.4 million barrels of storage capacity for crude oil, gasoline, intermediates and blendstocks, and distillates, including 500,000 barrels of leased storage capacity from an adjacent landowner.
 
Wholesale Segment
 
Our wholesale group includes several lubricant and bulk petroleum distribution plants, unmanned fleet fueling operations, a bulk lubricant terminal facility, and a fleet of crude oil and finished product trucks and lubricant delivery trucks. The wholesale group distributes commercial wholesale petroleum products primarily in Arizona, California, Colorado, Nevada, New Mexico, Texas, and Utah. Our wholesale group purchases petroleum fuels and lubricants from our refining group and from third-party suppliers.
 
Our principal customers are unbranded retail fuel distributors and the mining, construction, utility, manufacturing, transportation, aviation, and agricultural industries. We compete with other wholesale petroleum products distributors in the areas we serve such as Pro Petroleum, Inc., Southern Counties Fuels, Union Distributing, Brown Evans Distributing Co., and Maxum Petroleum, Inc.
 
Retail Segment
 
Our retail group operates service stations that include convenience stores or kiosks. Our service stations sell various grades of gasoline, diesel fuel, general merchandise, and beverage and food products to the general public. Our wholesale group supplies substantially all the gasoline and diesel fuel that our retail group sells. We purchase general merchandise as well as beverage and food products from various suppliers. At February 25, 2011, our retail group operated 150 service stations with convenience stores or kiosks located in Arizona, New Mexico, and Colorado.
 
The main competitive factors affecting our retail segment are the location of the stores, brand identification, and product price and quality. Our service stations compete with Valero Energy Corp., Alon USA Energy, K&G Markets (formerly ConocoPhillips), Murphy Oil, Maverik, Circle K, Brewer Oil Company, Quick-Trip, am/pm, and 7-2-11 food stores. Large chains of retailers like Costco Wholesale Corp., Wal-Mart Stores Inc., and large grocery retailers compete in the motor fuel retail business. Many of these competitors are substantially larger than we are and because of their integrated operations, may be better able to withstand volatile conditions in the fuel market and lower profitability in merchandise sales.
 
At February 25, 2011, our retail group had 123 convenience stores branded Giant, one branded Western, and two branded Western Express. In addition, 14 units were branded Mustang and 10 were branded Sundial. Gasoline brands sold at these stores include Western, Giant, Mustang, Phillips 66, Conoco, and Shell.
 
                         
Location
  Owned     Leased     Total  
 
Arizona
    24       18       42  
New Mexico
    72       24       96  
Colorado
    10       2       12  
                         
      106       44       150  
                         
 
Governmental Regulation
 
All of our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use, and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of gasoline, diesel, and other fuels; and the monitoring and reporting of greenhouse gas emissions. Our operations also require numerous permits and authorizations under various environmental, health, and safety laws and regulations. Failure to comply with these permits or environmental, health, or safety laws generally could result in fines, penalties, or other sanctions, or a revocation of our permits. We


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have made significant capital and other expenditures to comply with these environmental, health, and safety laws. We anticipate significant capital and other expenditures with respect to continuing compliance with these environmental, health, and safety laws. For additional details on our capital expenditures related to regulatory requirements and our refinery capacity expansion and upgrade, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Spending.
 
Periodically, we receive communications from various federal, state, and local governmental authorities asserting violation(s) of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective action. We do not anticipate that any such matters currently asserted will have a material adverse impact on our financial condition, results of operations, or cash flows.
 
El Paso Refinery
 
The groundwater and certain solid waste management units and other areas at and adjacent to our El Paso refinery have been impacted by prior spills, releases, and discharges of petroleum or hazardous substances and are currently undergoing remediation by us and Chevron pursuant to certain agreed administrative orders with the Texas Commission on Environmental Quality, or TCEQ. Pursuant to our purchase of the north side of the El Paso refinery from Chevron, Chevron retained responsibility to remediate their solid waste management units in accordance with its Resource Conservation Recovery Act, or RCRA, permit, which Chevron has fulfilled. Chevron also retained liability for, and control of, certain groundwater remediation responsibilities, which are ongoing.
 
In May 2000, we entered into an Agreed Order with the Texas Natural Resources Conservation Commission, now known as the TCEQ, for remediation of the south side of our El Paso refinery property. In August 2000, we purchased a Pollution and Legal Liability and Clean-Up Cost Cap Insurance policy at a cost of $10.3 million, which was expensed in 2000. The policy is non-cancelable and covers environmental clean-up costs related to contamination that occurred prior to December 31, 1999, including the costs of the Agreed Order activities. The insurance provider assumed responsibility for all environmental clean-up costs related to the Agreed Order up to $20 million. In addition, under a settlement agreement with us, a subsidiary of Chevron is obligated to pay 60% of any Agreed Order environmental clean-up costs that would otherwise have been covered under the policy but that exceed the $20 million threshold. Under the policy, environmental costs outside the scope of the Agreed Order are covered up to $20 million and require payment by us of a deductible of $0.1 million per incident as well as any costs that exceed the covered limits of the insurance policy.
 
The U.S. Environmental Protection Agency, or EPA, has embarked on a Petroleum Refinery Enforcement Initiative, or EPA Initiative, whereby it is investigating industry-wide noncompliance with certain Clean Air Act rules. The EPA Initiative has resulted in many refiners entering into consent decrees typically requiring penalties and substantial capital expenditures for additional air pollution control equipment. Since December 2003, we have been voluntarily discussing a settlement pursuant to the EPA Initiative related to the El Paso refinery. Negotiations with the EPA regarding this Initiative have focused exclusively on air emission programs. We do not expect these negotiations to result in any soil or groundwater remediation or clean-up requirements. In May 2008, we and the EPA agreed on the basic EPA Initiative requirements related to the Fluid Catalytic Cracking Unit, or FCCU, and heaters and boilers that we expect will ultimately be incorporated into a final settlement agreement between us and the EPA. Based on current negotiations and information, we estimate the total capital expenditures necessary to address the EPA Initiative issues would be approximately $60 million, of which $38.8 million has already been expended, $15.2 million for the installation of a flare gas recovery system that was completed in 2007; and $23.6 million for nitrogen oxides, or NOx, emission controls on heaters and boilers was expended through 2010. We estimate remaining expenditures of approximately $21.2 million for the NOx emission controls on heaters and boilers from 2011 through 2013. This estimate may change depending upon the actual final settlement reached. We anticipate meeting the EPA Initiative NOx requirements for the FCCU using catalyst additives and therefore do not expect additional capital expenditures related to the EPA Initiative NOx requirements for the FCCU.
 
We received a proposed draft settlement agreement from the EPA in September 2009 demanding penalties of $1.5 million. We have accrued $1.5 million related to this matter. As of February 25, 2011, a final settlement between us and the EPA relating to this matter is still pending.


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In March 2008, the TCEQ had notified us that it would be presenting us with a proposed Agreed Order regarding six excess air emission incidents that occurred at the El Paso refinery during 2007 and early 2008. While at this time it is not known precisely how or when the Agreed Order may affect us, we may be required to implement corrective action under the Agreed Order and we may be assessed penalties. We do not expect any penalties or corrective action requested to have a material adverse effect on our business, financial condition, or results of operations or that any penalties assessed or increased costs associated with the corrective action will be material.
 
In 2004 and 2005, the El Paso refinery applied for and was issued a Texas Flexible Permit by the TCEQ Flexible Permits program, under which the refinery continues to operate. Established in 1994 under the Texas Clean Air Act, the program grants operational flexibility to industrial facilities and permits the allocation of emissions on a facility-wide basis in exchange for emissions reduction and controlling previously unregulated “grandfathered” emission sources. The TCEQ submitted its Flexible Permits Program rules to the EPA for approval in 1994 and has administered the program for 16 years with the EPA’s full knowledge. In May 2010, the El Paso refinery received a request from the EPA, pursuant to Section 114 of the Clean Air Act, seeking information about the refinery’s air permits. We responded to the EPA’s request in June 2010. Also in June 2010, the EPA disapproved the TCEQ Flexible Permits Program. In July 2010, the Texas Attorney General filed a legal challenge to the EPA’s disapproval in a federal appeals court asking for reconsideration. Although we believe our Texas Flexible Permit is federally enforceable, we agreed in December 2010 to submit within one year an application to TCEQ for a permit amendment to obtain an approved Texas State Implementation Plan, or SIP, air quality permit to address concerns raised by the EPA about all flexible permits. Sufficient time has not elapsed for us to reasonably estimate any potential impact of these regulatory developments in the Texas air permits program.
 
In September 2010, we received a notice of intent to sue under the Clean Air Act from several environmental groups. While not entirely clear, the notice apparently contends that our El Paso refinery is not operating under a valid permit or permits because the EPA has disapproved the TCEQ Flexible Permits program and that our El Paso refinery may have exceeded certain emission limitations under these same permits. We dispute these claims and maintain our El Paso refinery is properly operating, and has not exceeded emissions limitations, under the validly issued TCEQ permits. We intend to defend our refinery accordingly.
 
Four Corners Refineries
 
Four Corners 2005 Consent Agreements.  In July 2005, as part of the EPA Initiative, Giant reached an administrative settlement with the New Mexico Environment Department, or NMED, and the EPA in the form of consent agreements that resolved certain alleged violations of air quality regulations at the Gallup and Bloomfield refineries in the Four Corners area of New Mexico, or the 2005 NMED Agreement. In January 2009, we and the NMED agreed to an amendment of the 2005 administrative settlement with the NMED, or the 2009 NMED Amendment, which altered certain deadlines and allowed for alternative air pollution controls.
 
In November 2009, we indefinitely suspended refining operations at our Bloomfield refinery. We currently operate the site as a products distribution terminal and crude oil storage facility. We continue to operate certain Bloomfield refinery equipment to support the terminal and to store crude for our Gallup refinery. We are currently negotiating with the NMED to revise the 2009 NMED Amendment to reflect the indefinite suspension.
 
Based on current information and the 2009 NMED Amendment and favorably negotiating a revision to reflect the indefinite suspension of refining operations at our Bloomfield facility, we estimate $17.6 million total remaining capital expenditures will be required pursuant to the 2009 NMED Amendment. Through 2010, we have expended $5.9 million and expect to spend the remaining $11.7 million during 2011 and 2012. These capital expenditures will primarily be for installation of emission controls on the heaters, boilers, and FCCU, and for reducing sulfur in fuel gas to reduce emissions of sulfur dioxide and NOx and particulate matter from our Gallup refinery. The 2009 NMED Amendment also provided for a $2.4 million penalty. Payment of the penalty was completed between November 2009 and September 2010 to fund a Supplemental Environmental Project, or SEP. We do not expect implementation of the requirements in the 2005 NMED Agreement and the associated 2009 NMED Amendment will result in any soil or groundwater remediation or clean-up costs.
 
Bloomfield 2007 NMED Remediation Order.  In July 2007, we received a final administrative compliance order from the NMED alleging that releases of contaminants and hazardous substances that have occurred at the


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Bloomfield refinery over the course of its operation prior to June 1, 2007, have resulted in soil and groundwater contamination. Among other things, the order requires us to:
 
  •  investigate and determine the nature and extent of such releases of contaminants and hazardous substances;
 
  •  perform interim remediation measures, or continue interim measures already begun, to mitigate any potential threats to human health or the environment from such releases;
 
  •  identify and evaluate alternatives for corrective measures to clean up any contaminants and hazardous substances released at the refinery and prevent or mitigate their migration at or from the site;
 
  •  implement any corrective measures that may be approved by the NMED;
 
  •  develop investigation work plans over a period of approximately four years; and
 
  •  implement corrective measures pursuant to the investigation.
 
The order recognizes that prior work satisfactorily completed may fulfill some of the foregoing requirements. In that regard, we have already put in place some remediation measures with the approval of the NMED and New Mexico Oil Conservation Division.
 
Based on current information, we estimate a remaining undiscounted cost of $3.3 million for implementing the investigation and interim measures of the order. As of December 31, 2010, we had a liability of $2.5 million relating to the investigation and interim measures of the order implementation costs. As of December 31, 2010, we had expended $2.3 million to implement the order.
 
Gallup 2007 Resource Conservation and Recovery Act, or RCRA, Inspection.  In September 2007, our Gallup refinery was inspected jointly by the EPA and the NMED, or the Gallup 2007 RCRA Inspection, to determine compliance with the EPA’s hazardous waste regulations promulgated pursuant to the RCRA. We reached a final settlement with the agencies in August 2009 and paid a penalty of $0.7 million in October 2009. We do not expect implementation of the requirements in the final settlement will result in any soil or groundwater remediation or clean-up costs. We currently estimate $15.4 million in capital expenditures to upgrade the wastewater treatment plant at the Gallup refinery pursuant to the requirements of the final settlement. Through 2010, we have expended $4.2 million on the upgrade of the wastewater treatment plant and expect to spend the remaining $11.2 million during 2011 and 2012. In April 2010, we submitted a plan with the design and construction schedule to upgrade the wastewater treatment plant to the NMED for approval. We negotiated with the NMED and the EPA regarding modifications to the plan issued by the NMED in its May 2010 approval letter, which resulted in a September 2010 modification to the August 2009 final settlement establishing a May 2012 deadline for start-up of the upgraded wastewater treatment plant.
 
Gallup 2010 NMED Compliance Order.  In late October 2010, the NMED issued a proposed compliance order to us alleging violations of air quality regulations and permits related to certain emission limits at our Gallup refinery. The violations are alleged to have occurred at various times between March 2009 and October 2010. Under this compliance order, we have been assessed a penalty of $0.6 million. We are currently evaluating the merits of the alleged violations described in the compliance order. As the outcome of ongoing discussions or negotiations with the NMED is uncertain, we cannot reasonably estimate the liability under the order at this time. No amounts have been accrued at December 31, 2010 for this matter.
 
Yorktown Refinery
 
Yorktown 1991 and 2006 Orders.  Giant and a subsidiary company assumed certain liabilities and obligations in connection with the 2002 purchase of the Yorktown refinery from BP Corporation North America Inc. and BP Products North America Inc., or collectively BP, and BP agreed to indemnify Giant for certain costs. During 2007, BP disputed indemnification for certain costs. In the related lawsuit styled Western Refining Yorktown, Inc. f/k/a Giant Yorktown, Inc. v. BP Corporation North America, Inc. and BP Products North America, Inc., all claims and counterclaims were voluntarily dismissed with prejudice in 2009 by mutual agreement of the parties.


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In August 2006, Giant agreed to the terms of the final administrative consent order pursuant to which Giant would implement a clean-up plan for the refinery. Following the acquisition of Giant, we completed the first phase of the soil clean-up plan and negotiated revisions with the EPA for the remainder of the soil clean-up plan. We anticipate completing the requirements of the soil clean-up in 2011.
 
We currently estimate total remediation expenditures of $39.1 million associated with the EPA order. Through December 2010, we have expended $22.7 million related to the EPA order. We anticipate further expenditures of $16.0 million primarily during 2011 with the remainder over the next 29 years, ending in 2040. The EPA issued an approval in January 2010 that allowed us to begin implementing our revised soil clean-up plan during the second quarter of 2010. The January 2010 EPA approval and a prior EPA approval in 2008 allowed adjustments to the cost estimates for the groundwater monitoring plan and reductions to our estimate of total remediation expenditures.
 
Yorktown 2002 Amended Consent Decree.  In May 2002, Giant acquired the Yorktown refinery and assumed certain environmental obligations including responsibilities under a consent decree, or Consent Decree, among various parties covering many locations entered into August 2001 under the EPA Initiative. Parties to the Consent Decree include the United States, BP Exploration and Oil Co., Amoco Oil Company, and Atlantic Richfield Company. As applicable to our Yorktown refinery, the Consent Decree required, among other things, a reduction of NOx, sulfur dioxide, and particulate matter emissions and upgrades to the refinery’s leak detection and repair program. We do not expect implementation of the Consent Decree requirements will require any soil or groundwater remediation or clean-up. Pursuant to the Consent Decree and prior to May 31, 2007, Giant had installed a new sour water stripper and sulfur recovery unit with a tail gas treating unit and an electrostatic precipitator on the FCCU and had begun using sulfur dioxide emissions reducing catalyst additives in the FCCU. We temporarily suspended refining operations at our Yorktown facility in September 2010. Until such time that local market economics can support sustained profitable refining operations, we intend to operate our Yorktown facility as a product distribution terminal only. We expect additional capital expenditures to complete implementation of the Consent Decree requirements when refining operations are resumed. Our current estimate for these capital expenditures is $5.0 million and could differ significantly from what is required when refining operations are resumed. We do not expect that completing the requirements of the Consent Decree will result in material increased operating costs, nor do we expect the completion of these requirements to have a material adverse effect on our business, financial condition, or results of operations.
 
In March 2010, the EPA demanded stipulated penalties in the amount of $0.5 million, pursuant to the Consent Decree, for a flaring event that occurred at our Yorktown refinery in October 2009. In April 2010, we met with the EPA and provided additional written clarifying information in anticipation that the EPA will consider the information as the basis for reducing the agency’s demand for stipulated penalties. We continue to communicate with the EPA regarding the additional information provided. To allow discussions to continue, the EPA clarified its position in May 2010, stating that the March 2010 letter did not constitute a demand pursuant to the Consent Decree. We do not expect any penalties, corrective action, or other associated settlement costs related to this issue to have a material adverse effect on our business, financial condition, or results of operations.
 
Yorktown EPA EPCRA Potential Enforcement Notice.  In January 2010, the EPA issued our Yorktown refinery a notice to “show cause” why the EPA should not bring an enforcement action pursuant to the notification requirements under the Emergency Planning and Community Right-to-Know Act related to two separate flaring events that occurred in 2007 prior to our acquisition of Giant. We reached a settlement of this enforcement notice with the EPA in June 2010 for $0.2 million. As of December 31, 2010, the entire penalty has been paid to the EPA.
 
Regulation of Fuel Quality
 
The EPA adopted regulations under the Clean Air Act that require significant reductions in the sulfur content in gasoline, on-road diesel fuel, and off-road diesel fuel. These regulations required most refineries to begin reducing sulfur content in gasoline to 30 parts per million, or ppm, on January 1, 2004, with full compliance by January 1, 2006, and require reductions in sulfur content in on-road diesel to 15 ppm beginning on June 1, 2006, with full compliance by January 1, 2010. Qualified “small refiners” or refiners seeking and receiving hardship waivers with compliance plans from the EPA were allowed additional time under these regulations to comply.


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Under the EPA’s regulations, all on-road and off-road diesel, with the exception of off-road diesel for locomotive and marine use, must meet a 15 ppm sulfur standard as of June 2010. Off-road diesel produced for locomotive and marine use is allowed to meet the 500 ppm sulfur standard through May 2012. Our El Paso refinery implemented the 15 ppm sulfur standard for on-road diesel by April 2006 and the interim 500 ppm standard for off-road diesel by December 2009. Our Yorktown refinery implemented the 15 ppm sulfur standard for on-road and off-road diesel by February 2007 under a modified compliance plan. Our Gallup refinery implemented the 15 ppm sulfur standard for on-road diesel by June 2006, and was allowed to produce, under the flexibility of the regulation, up to 20% by volume of its on-road diesel at 500 ppm sulfur through May 2010. Our Gallup refinery implemented the interim 500 ppm standard for off-road diesel by June 2007 and was allowed to produce off-road diesel at this standard through May 2010. Our Gallup refinery currently relies on operational and marketing changes to meet the on-road and off-road diesel 15 ppm sulfur standard.
 
By June 2012, all locomotive and marine diesel must also meet the 15 ppm sulfur standard. EPA regulations allow the one-time use of credits to extend the June 2012 deadline by up to 24 months. Low sulfur credits purchased in 2010 will allow our El Paso refinery to continue producing 500 ppm sulfur locomotive fuel until late 2013. Our Yorktown refinery met this requirement before refining operations were suspended in 2010. We are evaluating the need for capital expenditures to produce 15 ppm sulfur locomotive fuel.
 
Our Yorktown refinery was producing 30 ppm gasoline by May 1, 2008, as required by its EPA compliance plan. Our El Paso refinery began producing low sulfur gasoline by August 1, 2009, as required by the EPA compliance plan for Yorktown and following our loss of “small refiner” status after the 2007 Giant acquisition. All of our refineries meet the requirements of the EPA’s low sulfur gasoline regulations. For additional details, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Spending.
 
Pursuant to the Energy Acts of 2005 and 2007, the EPA has issued Renewable Fuels Standards, or RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced at our refineries. The standards have been enforced at our El Paso refinery since September 2007. Our Gallup refinery became subject to RFS in January 2011 and will remain so unless the EPA grants a further extension to small refineries based on a U.S. Department of Energy study. Our Yorktown refinery will be subject to RFS when we restart refinery operations unless the EPA grants a further extension. Annually, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. The obligated volume increases over time until 2022. Blending renewable fuels into their finished petroleum fuels will displace an increasing volume of a refinery’s product pool. In 2010, the RFS obligation for ethanol and biodiesel for our El Paso refinery was met by blending at El Paso and also by transferring credits from blending at our Yorktown and Gallup refineries, the product distribution terminals in Albuquerque and Bloomfield, and the purchase of third-party credits.
 
Our El Paso and Gallup refineries are required to meet the new Mobile Source Air Toxics, or MSAT II, regulations to reduce the benzene content of gasoline. Under the MSAT II regulations, benzene in the finished gasoline pool must be reduced to an annual average of 0.62 volume percent by 2011. Beginning on July 1, 2012, each refinery must also average 1.30 volume percent benzene without the use of credits. As of December 31, 2010, we have expended $62.0 million to comply with MSAT II regulations at our El Paso refinery by completing construction of a benzene saturation unit in 2010, which is scheduled for start-up in March 2011. Early credits generated in 2009 and 2010 from the operation of our Yorktown refinery will be used by our Gallup refinery to comply with the 0.62 volume percent requirement. We anticipate $2.0 million or less in capital expenditures during 2011 and 2012 for our Gallup refinery to meet the 1.30 volume percent requirement. Our Yorktown refinery met the 1.30 volume percent benzene requirement prior to our temporarily suspending Yorktown refining activity and had planned to rely on credits to comply with the 0.62 volume percent requirement.
 
Several northeast states have proposed legislation to reduce the sulfur content of home heating oil. New Jersey has published a rule change that would require 500 ppm sulfur home heating oil beginning July 2014 and 15 ppm sulfur home heating oil beginning July 2016. New York has passed legislation to implement the 15 ppm sulfur level


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in July 2012. Before refining operations were suspended at our Yorktown refinery during 2010, it produced home heating oil that complied with the 3,000 ppm sulfur specification, but lacked the processing capability to produce heating oil that would comply with the revised standards. Implementation of these new standards will potentially reduce the market for 3.000 ppm sulfur home heating oil resulting in changes to our product slate and profitability when we restart refining operations at our Yorktown refinery.
 
Environmental Remediation
 
Certain environmental laws hold current or previous owners or operators of real property liable for the costs of cleaning up spills, releases, and discharges of petroleum or hazardous substances, even if these owners or operators did not know of and were not responsible for such spills, releases, and discharges. These environmental laws also assess liability on any person who arranges for the disposal or treatment of hazardous substances, regardless of whether the affected site is owned or operated by such person. We may face currently unknown liabilities for clean-up costs pursuant to these laws.
 
In addition to clean-up costs, we may face liability for personal injury or property damage due to exposure to chemicals or other hazardous substances that we may have manufactured, used, handled, disposed of, or that are located at or released from our refineries or otherwise related to our current or former operations. We may also face liability for personal injury, property damage, natural resource damage, or for clean-up costs for the alleged migration of petroleum or hazardous substances from our refineries to adjacent and other nearby properties.
 
Employees
 
As of February 25, 2011, we employed approximately 2,950 people, approximately 380 of whom were covered by collective bargaining agreements. Subject to a Memorandum of Understanding dated August 23, 2010, between Western Refining Yorktown, Inc. and the local union representing the covered Yorktown refinery employees, the collective bargaining agreement at our Yorktown refinery was terminated in connection with the temporary suspension of refining activities at our Yorktown facility. If we restart refining operations at our Yorktown facility prior to March 15, 2012, the collective bargaining agreement for covered Yorktown employees will be reinstated. All separated covered employees have recall rights if we restart Yorktown refining operations prior to March 16, 2012. In 2008, we successfully negotiated collective bargaining agreements covering employees at our Gallup and Bloomfield refineries that expire in 2011 and 2012, respectively. Although the collective bargaining agreement remains in force, the covered employees at our Bloomfield refinery were terminated in connection with the indefinite suspension of refining operations at our Bloomfield facility during November 2009. We also successfully negotiated a new collective bargaining agreement covering employees at our El Paso refinery, renewing the collective bargaining agreement that expired in April 2009. The collective bargaining agreement covering the El Paso refinery employees expires in April 2012. While all of our collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires. Accordingly, we may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our business, financial condition, and results of operations.
 
Available Information
 
We file reports with the Securities and Exchange Commission, or SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, and other reports from time to time. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC’s Internet site at http://www.sec.gov contains the reports, proxy, and information statements, and other information filed electronically.
 
As required by Section 406 of the Sarbanes-Oxley Act of 2002, we have adopted a code of ethics that applies specifically to our Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer. We have also adopted a Code of Business Conduct and Ethics applicable to all our directors, officers, and employees. Those codes of ethics are posted on our website. Within the time period required by the SEC and the New York Stock Exchange,


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or NYSE, we will post on our website any amendment to our code of ethics and any waiver applicable to any of our Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer. Our website address is: http://www.wnr.com. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under “Investor Relations,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports simultaneously to the electronic filings of those materials with, or furnishing of those materials to, the SEC. We also make available to shareholders hard copies of our complete audited financial statements free of charge upon request.
 
On June 24, 2010, the Company’s Chief Executive Officer certified to the NYSE that he was not aware of any violation by the Company of the NYSE’s corporate governance listing standards. In addition, attached as Exhibits 31.1 and 31.2 to this Form 10-K are the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002.
 
Item 1A.   Risk Factors
 
An investment in our common shares involves risk. In addition to the other information in this report and our other filings with the SEC, you should carefully consider the following risk factors in evaluating us and our business.
 
The price volatility of crude oil, other feedstocks, refined products, and fuel and utility services has had and may continue to have a material adverse effect on our earnings and cash flows.
 
Our earnings and cash flows from operations depend on the margin above fixed and variable expenses (including the cost of refinery feedstocks, such as crude oil) at which we are able to sell refined products. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products, and fuel and utility services. In particular, our refining margins were significantly lower in 2010 and 2009 compared to 2008 and 2007 due to decreased demand for refined products, substantial increases in feedstock costs, and lower increases in product prices throughout much of 2009 and 2010.
 
In recent years, the prices of crude oil, other feedstocks, and refined products have fluctuated substantially. The NYMEX WTI postings of crude oil for 2010 ranged from $68.01 to $91.51 per barrel. Prices of crude oil, other feedstocks, and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, and other refined products. Such supply and demand are affected by, among other things:
 
  •  changes in global and local economic conditions;
 
  •  demand for crude oil and refined products, especially in the U.S., China, and India;
 
  •  worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa, and Latin America;
 
  •  the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstocks, and refined products imported into the U.S., which can be impacted by accidents, interruptions in transportation, inclement weather, or other events affecting producers and suppliers;
 
  •  U.S. government regulations;
 
  •  utilization rates of U.S. refineries;
 
  •  changes in fuel specifications required by environmental and other laws;
 
  •  the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain oil price and production controls;
 
  •  development and marketing of alternative and competing fuels;
 
  •  pricing and other actions taken by competitors that impact the market;


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  •  product pipeline capacity, including the Magellan Southwest System pipeline, as well as Kinder Morgan’s expansion of its East Line, both of which could increase supply in certain of our service areas and therefore reduce our margins;
 
  •  accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our plants, machinery or equipment, or those of our suppliers or customers; and
 
  •  local factors, including market conditions, weather conditions, and the level of operations of other refineries and pipelines in our service areas.
 
Volatility has had, and may continue to further have, a negative effect on our results of operations to the extent that the margin between refined product prices and feedstock prices narrows further, as was the case throughout much of 2009 and 2010.
 
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities. As a result, we have no control over the changing market value of these inventories. Because our inventory of crude oil and refined product is valued at the lower of cost or market value under the “last-in, first-out,” or LIFO, inventory valuation methodology, if the market value of our inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of products sold. The estimated fair value of the Giant inventory recorded as a result of the acquisition of Giant increased the likelihood of a lower of cost or market, or LCM, inventory write-down to occur in the future. As a result of increasing market prices of crude oil, blendstocks, and refined products, we had a net change in the lower of cost or market reserve from December 31, 2008 to December 31, 2009 of $61.0 million to value our Yorktown inventories to net realizable market values, which decreased cost of products sold and increased refinery gross margin for the year ended December 31, 2009. In addition, due to the volatility in the price of crude oil and other blendstocks, we experienced fluctuations in our LIFO reserves during the three years ended December 31, 2010. We also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in decreases in cost of products sold of $16.9 million and $9.4 million for the years ended December 31, 2010 and 2009, and an increase in cost of products sold of $66.9 million for the year ended December 31, 2008.
 
In addition, the volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refineries affects operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our results of operations.
 
If the price of crude oil increases significantly or our credit profile changes, or if we are unable to access our Revolving Credit Agreement for borrowings or for letters of credit, our liquidity and our ability to purchase enough crude oil to operate our refineries at full capacity could be materially and adversely affected.
 
We rely on borrowings and letters of credit under our Revolving Credit Agreement to purchase crude oil for our refineries. Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require additional support such as letters of credit. Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our creditors of more burdensome payment terms on us, or our inability to access our Revolving Credit Agreement, may have a material adverse effect on our liquidity and our ability to make payments to our suppliers, which could hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. In addition, if the price of crude oil increases significantly, we may not have sufficient capacity under our Revolving Credit Agreement, or sufficient cash on hand, to purchase enough crude oil to operate our refineries at planned rates. A failure to operate our refineries at planned rates could have a material adverse effect on our earnings and cash flows.


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We have a significant amount of indebtedness.
 
As of December 31, 2010, our total debt was $1,069.5 million and our stockholders’ equity was $675.6 million. On December 23, 2010, we completed an amendment of our Revolving Credit Agreement, resulting in total commitments of $800.0 million composed of a $145.0 million tranche maturing on May 31, 2012 and a $655.0 million tranche maturing on January 1, 2015. As of December 31, 2010, the gross availability under the Revolving Credit Agreement was $624.0 million pursuant to the borrowing base. As of December 31, 2010, we had net availability under the Revolving Credit Agreement of $335.6 million due to $288.4 million in letters of credit outstanding and no direct borrowings. On February 25, 2011, the gross availability under the Revolving Credit Agreement was $650.3 million pursuant to the borrowing base. On February 25, 2011, we had net availability under the Revolving Credit Agreement of $192.3 million due to $273.0 million in letters of credit outstanding and $185.0 million in direct borrowings. Our level of debt may have important consequences to you. Among other things, it may:
 
  •  limit our ability to use our cash flow, or obtain additional financing, for future working capital, capital expenditures, acquisitions, or other general corporate purposes;
 
  •  restrict our ability to pay dividends;
 
  •  require a substantial portion of our cash flow from operations to make debt service payments;
 
  •  limit our flexibility to plan for, or react to, changes in our business and industry conditions;
 
  •  place us at a competitive disadvantage compared to our less leveraged competitors; and
 
  •  increase our vulnerability to the impact of adverse economic and industry conditions and, to the extent of our outstanding debt under our floating rate debt facilities, the impact of increases in interest rates.
 
We cannot assure you that we will continue to generate sufficient cash flows or that we will be able to borrow funds under our Revolving Credit Agreement in amounts sufficient to enable us to service our debt or meet our working capital and capital expenditure requirements. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses. If our margins were to deteriorate significantly, or if our earnings and cash flow were to suffer for any other reason, we may be unable to comply with the financial covenants set forth in our credit facilities. If we fail to satisfy these covenants, we could be prohibited from borrowing for our working capital needs and issuing letters of credit, which would hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. To the extent that we are unable to generate sufficient cash flows from operations, or if we are unable to borrow or issue letters of credit under the Revolving Credit Agreement, we may be required to sell assets, reduce capital expenditures, refinance all or a portion of our existing debt, or obtain additional financing through equity or debt financings. If additional funds are obtained by issuing equity securities or if holders of our outstanding 5.75% Convertible Senior Notes convert those notes into shares of our common stock, our existing stockholders could be diluted. We cannot assure you that we will be able to refinance our debt, sell assets, or obtain additional financing on terms acceptable to us, if at all. In addition, our ability to incur additional debt will be restricted under the covenants contained in our Revolving Credit Agreement, Term Loan Credit Agreement, and Senior Secured Notes. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Working Capital and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Indebtedness.
 
Covenants and events of default in our debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.
 
Our Revolving Credit Agreement, Term Loan Credit Agreement, or Term Loan, and the indenture governing our Senior Secured Notes contain covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. For instance, we are subject to covenants that restrict our activities, including restrictions on:
 
  •  creating liens;


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  •  engaging in mergers, consolidations, and sales of assets;
 
  •  incurring additional indebtedness;
 
  •  providing guarantees;
 
  •  engaging in different businesses;
 
  •  making investments;
 
  •  making certain dividend, debt, and other restricted payments;
 
  •  engaging in certain transactions with affiliates; and
 
  •  entering into certain contractual obligations.
 
We are also subject to financial covenants that require us to maintain, in the case of the Revolving Credit Agreement, a minimum fixed charge coverage ratio (as defined therein), contingent on the level of availability thereunder, and in the case of the Term Loan Credit Agreement, a minimum consolidated interest coverage ratio (as defined therein), and a maximum consolidated leverage ratio (as defined therein). Our ability to comply with these covenants will depend on factors outside our control, including refined product margins. We cannot assure you that we will satisfy these covenants. If we fail to satisfy the covenants set forth in these facilities or an event of default occurs under these facilities, the maturity of the loans, our Senior Secured Notes and our Convertible Senior Notes could be accelerated or we could be prohibited from borrowing for our working capital needs and issuing letters of credit. If the loans, our Senior Secured Notes, or our Convertible Senior Notes are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness, or to obtain additional financing through equity or debt financings. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all. If we cannot borrow or issue letters of credit under the Revolving Credit Agreement, we would need to seek additional financing, if available, or curtail our operations.
 
We have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
 
If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to comply with certain environmental standards by the current EPA mandated deadlines or pursue our business strategies, in which case our operations may not perform as well as we currently expect. We have substantial short-term and long-term capital needs, including those for capital expenditures that we will make to comply with various regulatory requirements. Our short-term working capital needs are primarily crude oil purchase requirements, which fluctuate with the pricing and sourcing of crude oil. We also have significant long-term needs for cash, including those to support ongoing capital expenditures and other regulatory compliance.
 
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs, or liabilities. Any significant interruptions in the operations of any of our refineries could materially and adversely affect our business, financial condition, and results of operations.
 
Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products, and refined products. These hazards and risks include, but are not limited to, the following:
 
  •  natural disasters;
 
  •  weather-related disruptions;
 
  •  fires;
 
  •  explosions;
 
  •  pipeline ruptures and spills;


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  •  third-party interference;
 
  •  disruption of natural gas deliveries;
 
  •  disruptions of electricity deliveries;
 
  •  disruption of sulfur gas processing by E.I. du Pont de Nemours at our El Paso refinery; and
 
  •  mechanical failure of equipment at our refineries or third-party facilities.
 
Any of the foregoing could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims, and other damage to our properties and the properties of others. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events. For example, in February 2011, we experienced several days of unplanned downtime at our El Paso refinery due to weather related causes and interruptions to our electrical supply. Furthermore, in any of those situations, undamaged refinery processing units may be dependent on or interact with damaged process units and, accordingly, are also subject to being shut down.
 
Our refineries consist of many processing units, several of which have been in operation for a long time. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs, or our planned turnarounds may last longer than anticipated. Scheduled and unscheduled maintenance could reduce our revenues and increase our costs during the period of time that our units are not operating.
 
Our refining activities are conducted at our El Paso refinery in Texas, the Yorktown refinery in Virginia, and our Gallup refinery in New Mexico. The refineries constitute a significant portion of our operating assets, and our refineries supply a significant portion of our fuel to our retail operations. Prior to our acquisition of Giant in 2007, there was one fire incident at the Yorktown refinery and two fire incidents at the Gallup refinery in late 2006. Because of the significance to us of our refining operations, the occurrence of any of the events described above could significantly disrupt our production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition, and results of operations.
 
Crude oil supplies for the El Paso refinery come from the Permian Basin in Texas and New Mexico and therefore are generally not subject to interruption from severe weather, such as hurricanes. We, however, obtain certain of our feedstocks for the El Paso refinery, such as alkylate, and some refined products we purchase for resale, by pipeline from Gulf Coast refineries. Alkylate is used to produce a portion of our Phoenix Clean Burning Gasoline, or CBG, and other refined products. If our supply of feedstocks is interrupted for the El Paso refinery, our business, financial condition, and results of operations could be adversely impacted.
 
Our operations involve environmental risks that could give rise to material liabilities.
 
Our operations, and those of prior owners or operators of our properties, have previously resulted in spills, discharges, or other releases of petroleum or hazardous substances into the environment, and such spills, discharges, or releases could also happen in the future. Past or future spills related to any of our operations, including our refineries, product terminals, or transportation of refined products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and clean-up responsibility) to governmental entities or private parties under federal, state, or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Responsibility, Compensation, and Liability Act, or CERCLA, for contamination of properties that we currently own or operate and facilities to which we transported or arranged for the transportation of wastes or by-products for use, treatment, storage or disposal, without regard to fault or whether our actions were in compliance with law at the time. Our liability could also increase if other responsible parties, including prior owners or operators of our facilities, fail to complete their clean-up obligations. Based on current information, we do not believe these liabilities are likely to have a material adverse effect on our business, financial condition, or results of operations. In the event that new spills, discharges, or other releases of petroleum or hazardous substances occur or are discovered or there are other changes in facts or in the level of contributions being made by other responsible parties, there could be a material adverse effect on our business, financial condition, and results of operations.


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In addition, we may face liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our refineries or otherwise related to our current or former operations. We may also face liability for personal injury, property damage, natural resource damage, or for clean-up costs for the alleged migration of contamination or other hazardous substances from our refineries to adjacent and other nearby properties.
 
We may incur significant costs to comply with environmental and health and safety laws and regulations.
 
Our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use, and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, characteristics, composition of gasoline, diesel, and other fuels and the monitoring and reporting of greenhouse gas emissions. If we fail to comply with these regulations, we may be subject to administrative, civil, and criminal proceedings by governmental authorities, as well as civil proceedings by environmental groups and other entities and individuals. A failure to comply, and any related proceedings, including lawsuits, could result in significant costs and liabilities, penalties, judgments against us, or governmental or court orders that could alter, limit, or stop our operations.
 
In addition, new environmental laws and regulations, including new regulations relating to alternative energy sources, new state regulations relating to fuel quality, and the risk of global climate change, as well as new interpretations of existing laws and regulations, increased governmental enforcement, or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted, or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, and results of operations.
 
The EPA has issued rules pursuant to the Clean Air Act that require refiners to reduce the sulfur content of gasoline and diesel fuel and reduce the benzene content of gasoline by various specified dates. We are incurring substantial costs to comply with the EPA’s low sulfur and low benzene rules. Our strategy for complying with low sulfur gasoline regulations at our El Paso refinery and our strategy for complying with low sulfur gasoline regulations at our El Paso and Gallup refineries relies partially on purchasing credits. If credits are not available or are too costly, we may not be able to meet the EPA’s deadlines using a credit strategy. Failure to meet the EPA’s clean fuels mandates could have a material adverse effect on our business, financial condition, and results of operations.
 
Pursuant to the Energy Acts of 2005 and 2007, the EPA has issued Renewable Fuels Standards, or RFS, implementing mandates to blend renewable fuels into the petroleum fuels produced at our refineries. Currently, the standards are enforced at our El Paso refinery only. Our Gallup refinery became subject to RFS in 2011 and will remain subject unless the EPA grants further extensions to small refineries. Annually, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. The obligated volume increases over time until 2022. Blending renewable fuels into their finished petroleum fuels will displace an increasing volume of a refinery’s product pool. Alternatively, refineries can meet their RFS obligations by purchasing renewable identification numbers, or RINs. If sufficient RINs are unavailable for purchase, or if we are otherwise unable to meet the EPA’s RFS mandates, our business, financial condition and results of operations could be materially adversely affected.
 
We could incur significant costs to comply with greenhouse gas emissions regulation or legislation.
 
In November 2010, the State of New Mexico adopted regulations regarding greenhouse gas emissions. The regulations will become effective in 2012 unless reversed by the current New Mexico administration, or unless a certain amount of emissions are not available within New Mexico and other participating states. Our Gallup refinery will be required to reduce its greenhouse gas emissions by 2% per year between 2012 and 2020 or obtain emission credits from other regulated facilities. The EPA has recently adopted and implemented regulations to restrict


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emissions of greenhouse gases under certain provisions of the Clean Air Act. One of the rules adopted by the EPA requires a reduction in certain emissions of greenhouse gases from large stationary sources, such as refineries, effective January 2, 2011. A number of legal challenges have been presented regarding these proposed greenhouse gas regulations but no legal limitation on the EPA implementing these rules has occurred to date. The EPA has also adopted rules requiring refiners to report greenhouse gas emissions on an annual basis beginning in 2011 for emissions occurring after January 1, 2010. Further, the United States Congress has recently discussed legislation related to the reduction of greenhouse gases through “cap and trade” programs. To the extent these EPA rules and regulations continue to be implemented or cap and trade legislation is enacted by federal or state governments, our operating costs will increase and such increase could have an adverse effect on our business, financial condition, and results of operations.
 
Our business, financial condition, and results of operations may be materially adversely affected by a continued economic downturn.
 
The recent turmoil in the global financial markets and the scarcity of credit has led to lack of consumer confidence, increased market volatility, and widespread reduction of business activity generally in the United States and abroad. The economic downturn has materially adversely affected and may continue to affect the liquidity, businesses, and/or financial conditions of our customers, which has resulted, and may continue to result, not only in decreased demand for our products, but also increased delinquencies in our accounts receivable. The disruptions in the financial markets could also lead to a reduction in available trade credit due to counterparties’ liquidity concerns. If we are unable to obtain borrowings or letters of credit under our Revolving Credit Agreement, our business, financial condition, and results of operations could be materially adversely affected.
 
We could experience business interruptions caused by pipeline shutdown.
 
Our El Paso refinery, which is our largest refinery, is dependent on a pipeline owned by Kinder Morgan Energy Partners, LP, or Kinder Morgan, for the delivery of all of its crude oil. Because our crude oil refining capacity at the El Paso refinery is approaching the delivery capacity of the pipeline, our ability to offset lost production due to disruptions in supply with increased future production is limited due to this crude oil supply constraint. In addition, we will be unable to take advantage of further expansion of the El Paso refinery’s production without securing additional crude oil supplies or pipeline expansion. We also deliver a substantial percentage of the refined products produced at the El Paso refinery through three principal product pipelines. Any extended, non-excused downtime of our El Paso refinery could cause us to lose line space on these refined products pipelines if we cannot otherwise utilize our pipeline allocations. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil or refined products is disrupted because of accidents, governmental regulation, terrorism, other third-party action, or any other events beyond our control. A prolonged inability to receive crude oil or transport refined products on pipelines that we currently utilize could have a material adverse effect on our business, financial condition, and results of operations.
 
We also have a pipeline system that delivers crude oil and natural gas liquids to our Gallup refinery. The Gallup refinery is dependent on the crude oil pipeline system for the delivery of the crude oil necessary to run the refinery. If the operation of the pipeline system is disrupted, we may not receive the crude oil necessary to run the refinery. A prolonged inability to transport crude oil on the pipeline system could have a material adverse effect on our business, financial condition, and results of operations.
 
Certain rights-of-way necessary for our crude oil pipeline system to deliver crude oil to our Gallup refinery must be renewed periodically. A prolonged inability to use these pipelines to transport crude oil to our Gallup refinery could have a material adverse effect on our business, financial condition, and results of operations.
 
We may not have sufficient crude oil to be able to run our Gallup refinery at full capacity.
 
Our Gallup refinery purchases crude oil from the local regions around the refinery. To the extent sufficient local crude oil cannot be purchased and we are unable to transport sufficient crude oil on our 16-inch pipeline to supply the Gallup refinery, we may not have sufficient crude oil to run the Gallup refinery at the historical levels of


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our Four Corners refineries, which could have a material adverse impact on our business, financial condition, and results of operations.
 
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.
 
Our operations require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws and regulations. This includes our El Paso refinery’s Texas Flexible Permit. See Note 21, Contingencies — El Paso Refinery. These authorizations and permits are subject to revocation, renewal, or modification and can require operational changes, which may involve significant costs, to limit impacts or potential impacts on the environment and/or health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations.
 
Competition in the refining and marketing industry is intense, and an increase in competition in the areas in which we sell our refined products could adversely affect our sales and profitability.
 
We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations, and greater resources, some of our competitors may be better able to withstand volatile market conditions, to compete on the basis of price, to obtain crude oil in times of shortage, and to bear the economic risks inherent in all phases of the refining industry.
 
We are not engaged in the petroleum exploration and production business and therefore do not produce any of our crude oil feedstocks. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production. Competitors that have their own production are at times able to offset losses from refining operations with profits from production, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial, and individual consumers. If we are unable to compete effectively with these competitors, both within and outside of our industry, there could be a material adverse effect on our business, financial condition, and results of operations.
 
The areas where we sell refined products are also supplied by various refined product pipelines. Any expansions or additional product supplied by these third-party pipelines could put downward pressure on refined product prices in these areas.
 
Portions of our operations in the areas we operate may be impacted by competitors’ plans, as well as plans of our own, for expansion projects and refinery improvements that could increase the production of refined products in the Southwest region. In addition, we anticipate that lower quality crude oils, which are typically less expensive to acquire, can and will be processed by our competitors as a result of refinery improvements. These developments could result in increased competition in the areas in which we operate.
 
Our insurance policies do not cover all losses, costs, or liabilities that we may experience.
 
Our insurance coverage does not cover all potential losses, costs, or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience any more insurable events, our annual premiums could increase further or insurance may not be available at all. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our business, financial condition, and results of operations.


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A substantial portion of our refining workforce is unionized, and we may face labor disruptions that would interfere with our operations.
 
As of February 25, 2011, we employed approximately 2,950 people, approximately 380 of whom were covered by collective bargaining agreements. Subject to a Memorandum of Understanding dated August 23, 2010 between Western Refining Yorktown, Inc. and the local union representing the covered Yorktown refinery employees, the collective bargaining agreement at our Yorktown refinery was terminated in connection with the temporary suspension of refining activities at our Yorktown facility. If we restart refining operations at our Yorktown facility prior to March 15, 2012, the collective bargaining agreement for covered Yorktown employees will be reinstated. All separated covered employees have recall rights if we restart Yorktown refining operations prior to March 16, 2012. In 2008, we successfully negotiated collective bargaining agreements covering employees at our Gallup and Bloomfield refineries that expire in 2011 and 2012, respectively. Although the collective bargaining agreement remains in force, the covered employees at our Bloomfield refinery were terminated in connection with the indefinite suspension of refining operations at our Bloomfield facility during November 2009. We also successfully negotiated a new collective bargaining agreement covering employees at our El Paso refinery, renewing the collective bargaining agreement that expired in April 2009. The collective bargaining agreement covering the El Paso refinery employees expires in April 2012. While all of our collective bargaining agreements contain “no strike” provisions, those provisions are not effective in the event that an agreement expires. Accordingly, we may not be able to prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse affect on our business, financial condition, and results of operations.
 
Terrorist attacks, threats of war, or actual war may negatively affect our operations, financial condition, results of operations and prospects.
 
Terrorist attacks in the U.S. as well as events occurring in response to or in connection with them, may adversely affect our operations, financial condition, results of operations and prospects. Energy related assets (which could include refineries and terminals such as ours or pipelines such as the ones on which we depend for our crude oil supply and refined product distribution) may be at greater risk of future terrorist attacks than other possible targets. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations and prospects. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for our crude oil and refined products, and an adverse impact on the margins from our refining and marketing operations. In addition, disruption or significant increases in energy prices could result in government imposed price controls.
 
While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.
 
Long-lived and intangible assets comprise a significant portion of our total assets.
 
Long-lived assets and both amortizable intangible assets and intangible assets with indefinite lives must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of those assets may not be recoverable. We evaluate the remaining useful lives of our intangible assets with indefinite lives each reporting period. If events or circumstances no longer support an indefinite life, the intangible asset is tested for impairment and prospectively amortized over its remaining useful life. Long-lived and amortizable intangible assets are not recoverable if their carrying amount exceeds the sum of the undiscounted cash flows expected to result from their use and eventual disposition. If a long-lived or amortizable intangible asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined generally based on discounted estimated net cash flows.
 
In order to test long-lived and amortizable intangible assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected volumes, margins,


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cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
 
Due to the effect of the current unfavorable economic conditions on the refining industry, and our expectations of a continuation of such conditions for the near term, we will continue to monitor both our operating assets and our capital projects for potential asset impairments or project write-offs until conditions improve. Due to continuing losses resulting from narrow heavy light crude differentials, poor coking economics, and changes in our Yorktown crude oil purchase contracts, we have recently suspended refining operations at our Yorktown refinery. As such, our current evaluations are primarily focused on our Yorktown refinery long-lived assets, which had a carrying value of $678.5 million as of December 31, 2010. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus negatively affecting our earnings. See Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Long-lived Assets.
 
Our operating results are seasonal and generally lower in the first and fourth quarters of the year.
 
Demand for gasoline is generally higher during the summer months than during the winter months. In addition, ethanol is added to the gasoline in our service areas during the winter months, thereby increasing the supply of gasoline. This combination of decreased demand and increased supply during the winter months can lower gasoline prices. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. The effects of seasonal demand for gasoline are partially offset by increased demand during the winter months for diesel fuel in the Southwest and heating oil in the Northeast.
 
Our ability to pay dividends in the future is limited by contractual restrictions and cash generated by operations.
 
We are a holding company and all of our operations are conducted through our subsidiaries. Consequently, we will rely on dividends or advances from our subsidiaries to fund any dividends. The ability of our operating subsidiaries to pay dividends and our ability to receive distributions from those entities are subject to applicable local law. In addition, our ability to pay dividends to our shareholders is subject to certain restrictions in our Revolving Credit Agreement, our Term Loan Credit Agreement, and the indenture governing our Senior Secured Notes, including pro forma compliance with a fixed charge coverage ratio test and an excess availability test under our Revolving Credit Agreement, pro forma compliance with our minimum consolidated interest coverage ratio and maximum leverage ratio covenants and a fixed cap under our Term Loan Credit Agreement and compliance with an incurrence-based test and a formula-based maximum under the indenture governing our Senior Secured Notes. These factors could restrict our ability to pay dividends in the future. In addition, our payment of dividends will depend upon our ability to generate sufficient cash flows. Our board of directors will review our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.
 
Our controlling stockholders may have conflicts of interest with other stockholders in the future.
 
Mr. Paul Foster, our Executive Chairman, and Messrs. Jeff Stevens (our Chief Executive Officer and President and a current director), Ralph Schmidt (our former Chief Operating Officer and a current director) and Scott Weaver (our Vice President, Assistant Secretary and a current director) own approximately 41% of our common stock. As a result, Mr. Foster and the other members of this group will strongly influence or effectively control the election of our directors, our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales, and other significant corporate transactions. The interests of Mr. Foster and the other members of this group may not coincide with the interests of other holders of our common stock.


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If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.
 
Our future performance depends to a significant degree upon the continued contributions of our senior management team, including our Executive Chairman, Chief Executive Officer and President, Chief Financial Officer, Vice President and Assistant Secretary, President-Refining and Marketing, Senior Vice President-Legal, General Counsel and Secretary, Chief Accounting Officer, and Senior Vice President-Treasurer. We do not currently maintain key man life insurance with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors, our customers, and other companies operating in our industry. To the extent that the services of members of our senior management team would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
Our principal properties are described under Item 1. Business and the information is incorporated herein by reference. As of December 31, 2010, we were a party to a number of cancelable and non-cancelable leases for certain properties, including our corporate headquarters in El Paso and administrative offices in Tempe, Arizona. See Note 23, Operating Leases and Other Commitments, in the Notes to Consolidated Financial Statements included elsewhere in this annual report.
 
Item 3.   Legal Proceedings
 
In the ordinary conduct of our business, we are subject to periodic lawsuits, investigations and claims, including environmental claims and employee related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.
 
Item 4.   Reserved
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
Market Information
 
Our common stock began trading on the NYSE, on January 19, 2006 under the symbol “WNR.” As of February 25, 2011, we had 142 holders of record of our common stock. The following table summarizes the high


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and low sales prices of our common stock as reported on the NYSE Composite Tape for the quarterly periods in the past two fiscal years and dividends declared on our common stock for the same periods:
 
                         
                Dividends per
 
    High     Low     Common Share  
 
2010:
                       
First quarter
  $ 5.84     $ 4.03     $  
Second quarter
    5.90       4.30        
Third quarter
    5.42       4.01        
Fourth quarter
    10.78       5.09        
2009:
                       
First quarter
  $ 14.00     $ 7.83     $  
Second quarter
    16.30       6.65        
Third quarter
    8.13       5.45        
Fourth quarter
    7.00       4.45        
 
Our payment of dividends is limited under the terms of our Revolving Credit Agreement, our Term Loan Credit Agreement, and our Senior Secured Notes, and in part, depends on our ability to satisfy certain financial covenants.
 
Securities Authorized for Issuance Under Equity Compensation Plans
 
See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.


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Performance Graph
 
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any further filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, except to the extent we specifically incorporate it by reference into such filing.
 
The following graph compares the cumulative 59-month total stockholder return on the Company’s common stock relative to the cumulative total stockholder returns of the Standard & Poor’s, or S&P, 500 index, and a customized peer group of seven companies that includes: Alon USA Energy, Inc., Delek US Holdings Inc., Frontier Oil Corp., Holly Corp., Sunoco Inc., Tesoro Corp., and Valero Energy Corp. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock and peer group on January 19, 2006. The index on December 31, 2010, and its relative performance are tracked through this date. The stock price performance included in this graph is not necessarily indicative of future stock price performance.
 
COMPARISON OF 59-MONTH CUMULATIVE TOTAL RETURN
 
(PERFORMANCE GRAPH)
 
COMPARISON OF 59-MONTH CUMULATIVE TOTAL RETURN
(Tabular representation of data in graph above)
 
                                                                                                         
    Jan
  Mar
  Jun
  Sep
  Dec
  Mar
  Jun
  Sep
  Dec
  Mar
  Jun
  Sep
  Dec
2006-2008
  2006   2006   2006   2006   2006   2007   2007   2007   2007   2008   2008   2008   2008
 
Western Refining, Inc. 
  $ 100.00     $ 116.51     $ 116.51     $ 125.69     $ 137.92     $ 211.59     $ 313.75     $ 220.60     $ 131.94     $ 73.41     $ 64.91     $ 55.43     $ 42.54  
S&P 500
    100.00       101.15       99.69       105.34       112.40       113.12       120.22       122.66       118.58       107.38       104.45       95.71       74.70  
Peer Group
    100.00       98.70       106.90       86.68       88.23       110.65       129.14       114.97       116.78       81.67       66.61       52.05       41.46  
 
                                                                 
    Mar
    Jun
    Sep
    Dec
    Mar
    Jun
    Sep
    Dec
 
2009-2010
  2009     2009     2009     2009     2010     2010     2010     2010  
 
Western Refining, Inc. 
  $ 65.46     $ 38.71     $ 35.36     $ 25.82     $ 30.15     $ 27.58     $ 28.73     $ 58.00  
S&P 500
    66.48       77.07       89.09       94.47       99.56       88.19       98.15       108.70  
Peer Group
    35.35       32.81       38.44       34.12       38.98       37.57       38.13       48.90  
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
There were no purchases of equity securities by us or any of our affiliates during the quarter ended December 31, 2010. In addition, we currently do not have any share repurchase plans or programs.


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Item 6.   Selected Financial Data
 
The following tables set forth our summary of historical financial and operating data for the periods indicated below. The summary results of operations and financial position data for 2010, 2009, 2008, 2007, and 2006 have been derived from the consolidated financial statements of Western Refining, Inc. and its subsidiaries including Western Refining Company LP. On May 31, 2007, we completed the acquisition of Giant. The summary results of operations and financial position data for 2007 include the results of operations for Giant beginning June 1, 2007. The first full fiscal year in which we owned Giant was 2008, and therefore, the summary results of operations and financial position data for 2010, 2009, and 2008 are not comparable to periods prior to 2008.
 
The information presented below should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the financial statements and the notes thereto included in Item 8. Financial Statements and Supplementary Data.
 
                                         
    Year Ended December 31,  
    2010     2009     2008     2007(1)     2006  
    (In thousands, except per share data)  
 
Statement of Operations Data
                                       
Net sales
  $ 7,965,053     $ 6,807,368     $ 10,725,581     $ 7,305,032     $ 4,199,383  
Operating costs and expenses:
                                       
Cost of products sold (exclusive of depreciation and amortization)(2)
    7,155,967       5,944,128       9,735,500       6,385,623       3,644,391  
Direct operating expenses (exclusive of depreciation and amortization)
    444,531       486,164       532,325       382,690       171,729  
Selling, general, and administrative expenses
    84,175       109,697       115,913       77,350       37,043  
Goodwill and other impairment losses
    13,038       352,340                    
Maintenance turnaround expense
    23,286       8,088       28,936       15,947       22,196  
Depreciation and amortization
    138,621       145,981       113,611       64,193       13,624  
                                         
Total operating costs and expenses
    7,859,618       7,046,398       10,526,285       6,925,803       3,888,983  
                                         
Operating income (loss)
    105,435       (239,030 )     199,296       379,229       310,400  
                                         
Other income (expense):
                                       
Interest income
    441       248       1,830       18,852       10,820  
Interest expense and other financing costs
    (146,549 )     (121,321 )     (102,202 )     (53,843 )     (2,167 )
Amortization of loan fees
    (9,739 )     (6,870 )     (4,789 )     (1,912 )     (500 )
Write-off of unamortized loan fees
          (9,047 )     (10,890 )           (1,961 )
Loss on early extinguishment of debt
                      (774 )      
Other income (expense), net
    7,286       (15,184 )     1,176       (1,049 )     561  
                                         
Income (loss) before income taxes
    (43,126 )     (391,204 )     84,421       340,503       317,153  
Provision for income taxes
    26,077       40,583       (20,224 )     (101,892 )     (112,373 )
                                         
Net income (loss)
  $ (17,049 )   $ (350,621 )   $ 64,197     $ 238,611     $ 204,780  
                                         
Basic earnings (loss) per share
  $ (0.19 )   $ (4.43 )   $ 0.94     $ 3.50     $ 3.05  
Diluted earnings (loss) per share
    (0.19 )     (4.43 )     0.94       3.50       3.05  
Dividends declared per common share
  $     $     $ 0.06     $ 0.22     $ 0.16  
Weighted average basic shares outstanding
    88,204       79,163       67,715       67,180       65,387  
Weighted average dilutive shares outstanding
    88,204       79,163       67,715       67,180       65,387  


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    Year Ended December 31,  
    2010     2009     2008     2007(1)     2006  
    (In thousands, except per share data)  
 
Cash Flow Data
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 134,456     $ 140,841     $ 285,575     $ 113,237     $ 245,004  
Investing activities
    (73,777 )     (115,361 )     (220,554 )     (1,334,028 )     (149,555 )
Financing activities
    (75,657 )     (30,407 )     (274,769 )     1,247,191       (13,115 )
Other Data
                                       
Adjusted EBITDA(3)
  $ 288,107     $ 191,438     $ 405,854     $ 477,172     $ 357,601  
Capital expenditures
    78,095       115,854       222,288       277,073       120,211  
Cash paid for Giant acquisition, net of cash acquired
                      1,056,955        
Balance Sheet Data (at end of period)
                                       
Cash and cash equivalents
  $ 59,912     $ 74,890     $ 79,817     $ 289,565     $ 263,165  
Working capital
    272,750       311,254       314,521       621,362       276,609  
Total assets
    2,628,146       2,824,654       3,076,792       3,559,716       908,523  
Total debt
    1,069,531       1,116,664       1,340,500       1,583,500        
Stockholders’ equity
    675,593       688,452       811,489       756,485       521,601  
 
 
(1) Includes the results of operations and cash flows for Giant beginning June 1, 2007, the date of acquisition.
 
(2) Cost of products sold includes $21.7 million and $9.9 million, respectively, in economic hedging losses, for the years ended December 31, 2009 and 2007, and $11.4 million and $8.6 million, respectively, in economic hedging gains for the years ended December 31, 2008 and 2006. We previously reported economic hedging gains and losses as gain (loss) from derivative activities under other income (expense) in our Consolidated Statements of Operations for each of the periods indicated above. These prior year reclassifications were made to conform to the current presentation. Cost of products sold for the year ended December 31, 2010 includes $9.4 million in economic hedging losses.
 
(3) Adjusted EBITDA represents earnings before interest expense, income tax expense, amortization of loan fees, write-off of unamortized loan fees, loss on early extinguishment of debt, depreciation, amortization, goodwill and other impairment losses, maintenance turnaround expense, and Lower of Cost or Market, or LCM, inventory reserve adjustments. Adjusted EBITDA is not, however, a recognized measurement under United States generally accepted accounting principles, or GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of financings, income taxes, the accounting effects of significant turnaround activities (that many of our competitors capitalize and thereby exclude from their measures of EBITDA), acquisitions, and other items that may vary for different companies for reasons unrelated to overall operating performance.
 
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
 
• Adjusted EBITDA does not reflect our cash expenditures or future requirements for significant turnaround activities, capital expenditures, or contractual commitments;
 
• Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
 
• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs; and
 
• Our calculation of Adjusted EBITDA may differ from the Adjusted EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure.

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Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally. The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented:
 
                                         
    Year Ended December 31,  
    2010     2009     2008     2007(1)     2006  
    (In thousands)  
 
Net income (loss)
  $ (17,049 )   $ (350,621 )   $ 64,197     $ 238,611     $ 204,780  
Interest expense and other financing costs
    146,549       121,321       102,202       53,843       2,167  
Provision for income taxes
    (26,077 )     (40,583 )     20,224       101,892       112,373  
Amortization of loan fees
    9,739       6,870       4,789       1,912       500  
Write-off of unamortized loan fees
          9,047       10,890             1,961  
Loss on early extinguishment of debt
                      774        
Depreciation and amortization
    138,621       145,981       113,611       64,193       13,624  
Maintenance turnaround expense
    23,286       8,088       28,936       15,947       22,196  
Goodwill and other impairment losses
    13,038       352,340                    
Net change in LCM inventory reserve
          (61,005 )     61,005              
                                         
Adjusted EBITDA
  $ 288,107     $ 191,438     $ 405,854     $ 477,172     $ 357,601  
                                         


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this annual report. This discussion contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations. The cautionary statements made in this report should be read as applying to all related forward-looking statements wherever they appear in this report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under Part I — Item 1A. Risk Factors and elsewhere in this report. You should read such Risk Factors and Forward-Looking Statements. In this Item 7, all references to “Western Refining,” “the Company,” “Western,” “we,” “us,” and “our” refer to Western Refining, Inc., or WNR, and the entities that became its subsidiaries upon closing of our initial public offering (including Western Refining Company, L.P., or Western Refining LP), and Giant Industries, Inc., or Giant, and its subsidiaries, which became wholly-owned subsidiaries on May 31, 2007, unless the context otherwise requires or where otherwise indicated.
 
Company Overview
 
We are an independent crude oil refiner and marketer of refined products and also operate service stations and convenience stores. We own and operate two refineries with a total crude oil throughput capacity of approximately 151,000 barrels per day, or bpd. In addition to our 128,000 bpd refinery in El Paso, Texas, we own and operate a refinery near Gallup, New Mexico with a throughput capacity of approximately 23,000 bpd. Until September 2010, we operated a 70,000 bpd refinery on the East Coast of the United States near Yorktown, Virginia, and until November 2009, we also operated a 17,000 bpd refinery near Bloomfield, New Mexico. We temporarily suspended refining operations at our Yorktown facility in September 2010 and we indefinitely suspended refining operations at the Bloomfield refinery in November 2009. We continue to operate Yorktown and Bloomfield as product distribution terminals and supply refined products to those areas. Our primary operating areas encompass West Texas, Arizona, New Mexico, Utah, Colorado, and the Mid-Atlantic region. In addition to the refineries, we also own and operate stand-alone refined product distribution terminals in Albuquerque, New Mexico; Yorktown; and Bloomfield; as well as asphalt terminals in Phoenix and Tucson, Arizona; Albuquerque; and El Paso. As of December 31, 2010, we also own and operate 150 retail service stations and convenience stores in Arizona, Colorado, and New Mexico; a fleet of crude oil and finished product truck transports; and a wholesale petroleum products distributor, that operates in Arizona, California, Colorado, Nevada, New Mexico, Texas, and Utah.
 
On May 31, 2007, we completed the acquisition of Giant. Under the terms of the merger agreement, we acquired 100% of Giant’s 14,639,312 outstanding shares for $77.00 per share in cash for a total purchase price of $1,149.2 million, funded primarily through a $1,125.0 million secured term loan. In connection with the acquisition, we borrowed an additional $275.0 million in July 2007, when we paid off and retired Giant’s 8% and 11% Senior Subordinated Notes. Prior to the acquisition of Giant, we generated substantially all of our revenues from our refining operations in El Paso. With the acquisition of Giant, we also gained a diverse mix of complementary retail and wholesale businesses.
 
Following the acquisition of Giant, we began reporting our operating results in three business segments: the refining group, the wholesale group, and the retail group. Our refining group currently operates the two refineries and related refined product distribution terminals and asphalt terminals. At the refineries, we refine crude oil and other feedstocks into finished products such as gasoline, diesel fuel, jet fuel, and asphalt. Our refineries market finished products to a diverse customer base including wholesale distributors and retail chains. Our wholesale group distributes gasoline, diesel fuel, and lubricant products. Our retail group operates service stations and convenience stores and sells gasoline, diesel fuel, and merchandise. See Note 3, Segment Information, in the Notes to Consolidated Financial Statements included elsewhere in this annual report for detailed information on our operating results by segment.


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Major Influences on Results of Operations
 
Refining.  Our net sales fluctuate significantly with movements in refined product prices and the cost of crude oil and other feedstocks, all of which are commodities. The spread between crude oil and refined product prices is the primary factor affecting our earnings and cash flows from operations. The cost to acquire feedstocks and the price of the refined products that we ultimately sell depends on numerous factors beyond our control. These factors include the supply of and demand for crude oil, gasoline, and other refined products. Supply and demand for these products depend on changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; production levels; availability of imports; marketing of competitive fuels; price differentials between heavy and sour crude oils and light sweet crude oils, known as the heavy light crude oil differential; and government regulation. Refining margins experienced extreme volatility throughout 2008 and 2009. Refining margins were somewhat less volatile in 2010. Gasoline margin averages have improved each year since 2008 and average diesel margins for 2010 showed improvement over 2009 levels. Another factor impacting our margins in recent years is the narrowing of the heavy light crude oil differential. Since the second quarter of 2009, the heavy light crude oil differential has narrowed significantly, particularly impacting our Yorktown refinery which, when operating, can process up to 100% of heavy crude oil. Narrowing of the heavy light crude oil differential can have significant negative impact on our Yorktown refining margins, as was the case during 2009 and 2010. In addition, we had changes in our LCM reserve of $61.0 million related to our Yorktown inventories that increased our cost of products sold for the year ended December 31, 2008 and decreased our cost of products sold for the year ended December 31, 2009. There were no such LCM reserve changes in the year ended December 31, 2010.
 
Other factors that impact our overall refinery gross margins are the sale of lower value products such as residuum and propane, particularly when crude costs are higher. In addition, our refinery gross margin is further reduced because our refinery product yield is less than our total refinery throughput volume. Our results of operations are also significantly affected by our refineries’ direct operating expenses, especially the cost of natural gas used for fuel and the cost of electricity. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices.
 
Demand for gasoline is generally higher during the summer months than during the winter months. In addition, higher volumes of ethanol are blended with gasoline produced in the Southwest region during the winter months, thereby increasing the supply of gasoline. This combination of decreased demand and increased supply during the winter months can lower gasoline prices. As a result, our operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. The effects of seasonal demand for gasoline are partially offset by increased demand during the winter months for diesel fuel in the Southwest and heating oil in the Northeast. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends.
 
Safety, reliability, and the environmental performance of our refineries’ operations are critical to our financial performance. Unplanned downtime of our refineries, such as the unplanned weather-related outage our El Paso refinery experienced during February 2011, generally results in lost refinery gross margin opportunity, increased maintenance costs, and a temporary increase in working capital investment and inventory. We attempt to mitigate the financial impact of planned downtime, such as a turnaround or a major maintenance project, through a planning process that considers product availability, margin environment, and the availability of resources to perform the required maintenance.
 
Periodically we have planned maintenance turnarounds at our refineries, which are expensed as incurred. We shut down the south crude unit for 13 days at the El Paso refinery in the second quarter of 2009 and we performed a crude unit inspection outage for 20 days at the Yorktown refinery in October 2009. We completed a scheduled turnaround at the south side of the El Paso refinery during the first quarter of 2010. Our next scheduled maintenance turnarounds are during the first quarter of 2013 for El Paso and the fourth quarter of 2012 for Gallup.
 
The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Because crude oil and refined products are commodities, we have no control over the changing market value of these inventories. Our inventory of crude oil and the majority of our refined products are valued at the lower of cost or market value under the last-in, first-out, or LIFO, inventory valuation methodology. If the market values of our inventories decline below our cost basis, we would record a write-down of our inventories resulting in a non-


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cash charge to our cost of products sold. Market value declines during the year ended December 31, 2008 resulted in non-cash charges to our cost of products sold of $61.0 million. Under the LIFO inventory valuation method, this write-down is subject to recovery in future periods to the extent the market values of our inventories equal our cost basis relative to any LIFO inventory valuation write-downs previously recorded. Based on 2009 market conditions, we recorded non-cash recoveries of $61.0 million related to the 2008 LCM charges. In addition, due to the volatility in the price of crude oil and other blendstocks, we experienced fluctuations in our LIFO reserves between 2008 and 2009. We also experienced LIFO liquidations based on decreased levels in our inventories. These LIFO liquidations resulted in decreases in cost of products sold of $16.9 million and $9.4 million for the years ended December 31, 2010 and 2009, respectively, and an increase of $66.9 million in cost of products sold for the year ended December 31, 2008. See Note 5, Inventories, in the Notes to Consolidated Financial Statements included in this annual report for detailed information on the impact of LIFO inventory accounting.
 
Wholesale.  Our earnings and cash flows from our wholesale business segment are primarily affected by the sales volumes and margins of gasoline, diesel fuel, and lubricants sold. Margins for gasoline, diesel fuel, and lubricant sales are equal to the sales price less cost of sales. Margins are impacted by local supply, demand, and competition.
 
Retail.  Our earnings and cash flows from our retail business segment are primarily affected by the sales volumes and margins of gasoline and diesel fuel sold, and by the sales and margins of merchandise sold at our service stations and convenience stores. Margins for gasoline and diesel fuel sales are equal to the sales price less the delivered cost of the fuel and motor fuel taxes, and are measured on a cents per gallon, or cpg, basis. Fuel margins are impacted by local supply, demand, and competition. Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of supplier discounts and inventory shrinkage, and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding, and competition. Our retail sales are seasonal. Our retail business segment operating results for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.
 
Goodwill Impairment Loss.  Under our policy we test goodwill for impairment annually or more frequently if indications of impairment exist. Various indications of possible goodwill impairment prompted us to perform goodwill impairment analyses at December 31, 2008 and March 31, 2009. We determined that no such impairment existed as of those dates. Our annual 2009 impairment test was performed as of June 30, 2009. The performance of the test is a two-step process. Step 1 of the impairment test involves comparing the fair values of the applicable reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, we perform Step 2 of the goodwill impairment test to determine the amount of impairment loss. Step 2 of the goodwill impairment test involves comparing the implied fair value of the affected reporting unit’s goodwill against the carrying value of that goodwill.
 
From the first to the second quarter of 2009, there was a decline in margins within the refining industry as well as a downward change in industry analysts’ forecasts for the remainder of 2009 and 2010. This, along with other negative financial forecasts released by independent refiners during the latter part of the second quarter of 2009, contributed to declines in common stock trading prices within the independent refining sector, including declines in our common stock trading price. As a result, our equity market capitalization fell below the net book value of our assets. Through the filing date of our second quarter of 2009 Form 10-Q and through the end of the fourth quarter of 2009, the trading price of our stock had experienced further reductions.
 
We completed Step 1 of the impairment test during the second quarter of 2009 and concluded that impairment existed. Consistent with the preliminary Step 2 analysis completed during the second quarter of 2009, we concluded that our entire goodwill balance was impaired. The resulting non-cash charge of $299.6 million was reported in our second quarter of 2009 results of operations. We finalized our Step 2 analysis during the third quarter of 2009. There were no such impairment charges in previous years.
 
Long-lived Asset Impairment Loss.  We review the carrying values of our long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of assets to be held and used may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value.


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In order to test long-lived assets for recoverability, we must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, we must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected volumes, margins, cash flows, investment rates, interest/equity rates, and growth rates that could significantly impact the fair value of the asset being tested for impairment.
 
In the fourth quarter of 2009, we announced our plans to indefinitely suspend the refining operations at our Bloomfield refinery and operate the site as a product distribution terminal and crude oil storage facility. Accordingly, we tested our Bloomfield refinery long-lived assets and certain intangible assets for recoverability and determined that $41.8 million and $11.0 million of certain refinery related long-lived and intangible assets, respectively, were impaired. During the fourth quarter of 2010, we recorded an additional impairment charge of $9.1 million resulting from our fourth quarter 2010 analysis of specific assets that we had previously planned to relocate from our Bloomfield facility to our Gallup refinery. Based on the sustainable operational improvements of our Gallup refinery during 2010 that were beyond what we had anticipated at the time of the Bloomfield refinery idling, we determined that one of the three assets set aside for relocation to Gallup was no longer required to attain our desired levels of production. Non-cash impairment losses of $9.1 million and $52.8 million related to the long-lived assets and certain intangible assets are included under other impairment losses in the Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, respectively.
 
Factors Impacting Comparability of Our Financial Results
 
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.
 
Senior Secured Notes, Convertible Senior Notes, and Equity Offering
 
During the second and third quarters of 2009, we issued $600.0 million in Senior Secured Notes and $215.5 million in Convertible Senior Notes. The Senior Secured Notes consist of two tranches; the first consisting of $325.0 million in 11.25% fixed rate aggregate principal amount notes and the second consisting of $275.0 million floating rate aggregate principal amount notes. The interest rate on the floating rate notes was 10.75% at issuance in June 2009. Proceeds from the issuance of the Senior Secured Notes, net of original issue and underwriting discounts were $538.2 million. The Convertible Senior Notes consist of $215.5 million in 5.75% aggregate principal amount notes. The Convertible Senior Notes are unsecured and were issued with an initial conversion rate of 92.5926 shares of common stock per $1,000 principal amount of Convertible Senior Notes (equivalent to an initial conversion price of approximately $10.80 per share of common stock). Proceeds from the issuance of the Convertible Senior Notes were $209.0 million, net of underwriting discounts.
 
During the second quarter of 2009, we issued an additional 20,000,000 shares of our common stock for an aggregate amount of $180.0 million. The proceeds of this issuance were $171.0 million, net of $9.0 million in underwriting discounts.
 
The combined proceeds from the issuance and sale of the Senior Secured Notes, the Convertible Senior Notes, and our common stock were used to retire $912.7 million of our outstanding indebtedness under our Term Loan Credit Agreement. See Note 13, Long-Term Debt, and Note 18, Stockholders’ Equity, in the Consolidated Financial Statements included in this annual report for detailed information on the issuance and composition of these notes.
 
Asset Impairments
 
In the fourth quarter of 2009, we announced our plans to indefinitely suspend the refining operations at our Bloomfield refinery and maintain the site as a product distribution terminal and crude oil storage facility. Accordingly, we tested the Bloomfield refinery long-lived assets and certain intangible assets for recoverability and determined that $41.8 million and $11.0 million of certain Bloomfield refinery related long-lived and intangible assets, respectively, were impaired. During the fourth quarter of 2010, we recorded an additional impairment charge of $9.1 million resulting from our fourth quarter 2010 analysis of specific assets that we had previously planned to


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relocate from our Bloomfield facility to our Gallup refinery. Based on the current operations of the Gallup refinery, we have determined that one of the three assets set aside for relocation to Gallup is no longer required. Non-cash impairment losses of $9.1 million and $52.8 million related to the long-lived assets and certain intangible assets are included under other impairment losses in our Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, respectively.
 
We completed an impairment analysis of the long-lived assets at our Flagstaff, Arizona product distribution terminal following our permanent closure of the facility in the third quarter of 2010. The analysis determined that impairment existed, and we accordingly recorded a third quarter 2010 non-cash impairment charge of $3.8 million related to Flagstaff terminal long-lived assets. This charge is included under other impairment losses in our Consolidated Statement of Operations for the year ended December 31, 2010.
 
During the second quarter of 2009, we performed our annual impairment test and as a result concluded that all of our goodwill was impaired. The resulting non-cash charge of $299.6 million was reported in our second quarter 2009 results of operations. This charge is included under goodwill impairment loss in our Consolidated Statements of Operations for the year ended December 31, 2009.
 
Employee Benefit Plans
 
We terminated our defined benefit plan covering certain El Paso refinery employees during 2009. The termination resulted in a reduction to our related pension obligation of $24.3 million with a corresponding reduction of $25.1 million before the effect of income taxes to other comprehensive loss. During 2010, in connection with the temporary idling of our Yorktown refinery and resultant termination of participants of the Yorktown cash balance plan, we had distributed $12.8 million from plan assets to plan participants. As of December 31, 2010, the plan had not been terminated. The curtailment resulted in increases to the related pension obligation of $1.4 million and to other comprehensive loss (before income taxes) of $1.1 million. Subject to a Memorandum of Understanding between Western Refining Yorktown, Inc. and the local union representing the Yorktown refinery employees, eligible terminated employees, both bargained for and non-bargained for, were given the option of receiving severance pay or coverage under the Yorktown retiree medical plan, but not both. The resulting choices made by the terminated employees reduced our benefits obligation by $5.7 million as of December 31, 2010. Currently, we do not plan to terminate the Yorktown retiree medical plan.
 
Write-off of Unamortized Loan Fees
 
During the second and third quarters of 2009, we made principal payments on our Term Loan of $925.7 million primarily from the net proceeds of our debt and common stock offerings. Accordingly, we expensed $9.0 million during the second quarter of 2009 to write-off a portion of the unamortized loan fees related to the Term Loan. In June 2008, we amended our Revolving Credit Agreement and Term Loan. As a result of such amendment, we recorded an expense of $10.9 million related to the write-off of deferred loan fees incurred in May 2007. We completed an additional amendment to our Revolving Credit Agreement in December 2010. We will amortize all fees incurred as a result of this amendment, along with all unamortized loan fees related to the Revolving Credit Agreement prior to this amendment, ratably through the amended maturity date of January 2015. See Note 13, Long-Term Debt, in the Consolidated Financial Statements included in this annual report for detailed information on our long-term debt.
 
Environmental Cost Recoveries, Property Tax Refunds, and Other
 
During the latter part of March 2010, we reversed $14.7 million related to our accrued bonus for 2009. This revision of our 2009 bonus estimate reduced direct operating expenses and selling, general, and administrative expenses for 2010 by $8.5 million and $6.2 million, respectively. During 2009, we recovered $10.6 million from various third parties related to environmental costs recorded during 2009 and prior years. These recoveries are included in direct operating expenses reported for the year ended December 31, 2009. Additionally, during 2009, we decreased our property tax expense estimate by $5.5 million resulting from revised El Paso property appraisal rolls for 2006 through 2008. The revision to the property appraisal rolls also resulted in a refund of $2.9 million from


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various taxing authorities, further reducing our property tax expense for a total decrease of $8.4 million for the year ended December 31, 2009. We also recorded a fourth quarter 2009 legal settlement charge of $20.0 million.
 
Planned Maintenance Turnaround
 
During 2010 and 2009, we incurred costs of $23.3 million and $8.1 million, respectively for maintenance turnarounds. Primarily during the third and fourth quarters of 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter of 2010 at the El Paso refinery; and $1.2 million in connection with the planned turnaround in the third quarter of 2010 at the Yorktown refinery, which was subsequently cancelled. The 2008 maintenance turnaround was performed during the fourth quarter at the north side of the El Paso refinery. Our next scheduled maintenance turnarounds are during the first quarter of 2013 for El Paso and the fourth quarter of 2012 for Gallup. We expense the cost of maintenance turnarounds when the expense is incurred. Most of our competitors, however, capitalize and amortize maintenance turnarounds.
 
Critical Accounting Policies and Estimates
 
We prepare our financial statements in conformity with U.S. GAAP. In order to apply these principles, we must make judgments, assumptions, and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies, which are discussed below, could materially affect the amounts recorded in our financial statements.
 
Inventories.  Crude oil, refined product, and other feedstock and blendstock inventories are carried at the lower of cost or market. Cost is determined principally under the LIFO valuation method to reflect a better matching of costs and revenues. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of products sold in the period recorded. In subsequent periods, a new lower of cost or market determination is made based upon current circumstances. We determine market value inventory adjustments by evaluating crude oil, refined products, and other inventories on an aggregate basis by geographic region. Aggregated LIFO costs were less than the current cost of our crude oil, refined product, and other feedstock and blendstock inventories by $173.5 million at December 31, 2010.
 
Retail refined product (fuel) inventory values are determined using the first-in, first-out, or FIFO, inventory valuation method. Retail merchandise inventory value is determined under the retail inventory method. Wholesale finished product, lubricant, and related inventories are determined using the FIFO inventory valuation method. Finished product inventories originate from either our refineries or from third-party purchases.
 
Maintenance Turnaround Expense.  The units at our refineries require periodic maintenance and repairs commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit but generally is every two to six years depending on the processing unit involved. We expense the cost of maintenance turnarounds when the expense is incurred. These costs are identified as a separate line item in our Consolidated Statements of Operations.
 
Long-lived Assets.  We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. For assets to be disposed of, we report long-lived assets at the lower of carrying amount or fair value less cost of disposal.
 
We review the carrying values of our long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying amount of assets to be held and used may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value.
 
In order to test our long-lived assets for recoverability, we must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the


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asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, we must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates that could significantly impact the fair value of the asset being tested for impairment.
 
The economic slowdown that began in 2008 and continued into 2010 has reduced demand for refined products, thereby putting significant pressure on refined product margins. Beginning in the second quarter of 2009, heavy light crude oil differentials have narrowed significantly. Narrow heavy light crude oil differential has negatively impacted the results of operations of our Yorktown refinery. Due to these economic conditions, at December 31, 2009, we performed an impairment analysis of our Yorktown long-lived and intangible assets. This analysis indicated that the December 31, 2009 carrying value of our Yorktown long-lived assets was recoverable. Continuing losses due to narrow heavy light crude oil differentials, poor coking economics, changes in Yorktown crude oil purchase contract terms, and potentially significant regulatory capital spending requirements caused us to temporarily suspend our Yorktown refining operations during the third quarter of 2010. Accordingly, we revised our cash flow forecasts used in our analysis for long-lived asset impairment at our Yorktown refinery to reflect these changes in operations at the Yorktown facility as of June 30, 2010. The revised cash flows used in our June 30, 2010 impairment analysis assumes that refining operations will be temporarily suspended; that our Yorktown facility will be operated as a refined product terminal in the near term; and that restart activities will begin no later than the middle of 2013. Our revised forecast includes estimates and assumptions that require considerable judgment and are based on our historical production volumes and throughputs, industry analysts’ margin forecasts, financial forecasts, and industry trends and conditions. Based on our analysis, we determined that the undiscounted forecasted cash flows exceeded the carrying amount of our Yorktown long-lived and intangible assets as of June 30, 2010. No significant changes have occurred since we performed our analysis that would require us to revise our June 30, 2010 analysis. The carrying value of the long-lived assets related to refining operations that were temporarily idled could be subject to impairment. We currently anticipate a six to nine month pre-restart maintenance period will be required before our Yorktown refinery can be restarted, at an estimated cost of at least $50.0 million, which includes a maintenance turnaround. If our current plans to restart refining operations at our Yorktown facility within the next two to three years change, the likelihood of impairment of the long-lived assets and certain intangible assets related to the refinery operations will increase. Impairments related to Yorktown could have a material impact on our results of operations. The carrying value of total long-lived and intangible assets at Yorktown as of December 31, 2010 was $678.5 million, of which $472.4 million related to our Yorktown refining assets.
 
In the fourth quarter of 2009, we announced our plans to indefinitely suspend the refining operations at our Bloomfield refinery and maintain the site as a product distribution terminal and crude oil storage facility. Accordingly, we tested the Bloomfield refinery long-lived assets and certain intangible assets for recoverability and determined that $41.8 million and $11.0 million, respectively, of impairment losses existed in certain Bloomfield refinery related long-lived and intangible assets. During the fourth quarter of 2010, we recorded an additional impairment charge of $9.1 million resulting from our fourth quarter 2010 analysis of specific assets that we had previously planned to relocate from our Bloomfield facility to our Gallup refinery. Based on sustainable operational improvements at our Gallup refinery during 2010 that were beyond what we had anticipated at the time of the Bloomfield refinery idling, we determined that one of the three assets set aside for relocation to Gallup was no longer required to attain our desired levels of production. Non-cash impairment losses of $9.1 million and $52.8 million related to the long-lived assets and certain intangible assets are included under other impairment losses in our Consolidated Statements of Operations for the years ended December 31, 2010 and 2009, respectively. We currently plan to relocate and place the remaining Bloomfield refining assets with a net book value of $12.4 million at December 31, 2010 into service at the Gallup refinery during the maintenance turnaround scheduled for 2012.
 
During the third quarter of 2010, we permanently closed our product distribution terminal in Flagstaff, Arizona. We completed an impairment analysis of our Flagstaff terminal long-lived assets and determined from this analysis that the assets were fully impaired. Accordingly, an impairment charge of $3.8 million related to our Flagstaff long-lived assets is included in other impairment losses in the Consolidated Statements of Operations for the year ended December 31, 2010.


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Goodwill and Other Intangible Assets.  Goodwill represents the excess of the purchase price (cost) over the fair value of the net assets acquired and is carried at cost. We test goodwill for impairment at the reporting unit level annually. In addition, goodwill of a reporting unit is tested for impairment if any events and circumstances arise during a quarter that indicates goodwill of a reporting unit might be impaired. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. Within our refining segment, we have determined that we have three reporting units for purposes of assigning goodwill and testing for impairment. Our wholesale and retail segments are considered reporting units for purposes of assigning goodwill and testing for impairment. Our goodwill was assigned to two of our three refining reporting units and to our wholesale and retail reporting units. We do not amortize goodwill for financial reporting purposes.
 
Various indications of possible goodwill impairment prompted us to perform goodwill impairment analyses at December 31, 2008 and March 31, 2009. We determined that no such impairment existed as of those dates. Our 2009 annual impairment test was performed as of June 30, 2009. The performance of the test is a two-step process. Step 1 of the impairment test involves comparing the fair values of the applicable reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, we perform Step 2 of the goodwill impairment test to determine the amount of impairment loss. Step 2 of the goodwill impairment test involves comparing the implied fair value of the affected reporting unit’s goodwill against the carrying value of that goodwill.
 
From the first to the second quarter of 2009, there was a decline in margins within the refining industry as well as a downward change in industry analysts’ forecasts for the remainder of 2009 and 2010. This, along with other negative financial forecasts released by independent refiners during the latter part of the second quarter of 2009, contributed to declines in common stock trading prices within the independent refining sector, including declines in our common stock trading price. As a result, our equity market capitalization fell below the net book value of our assets. Through the filing date of our second quarter 2009 Form 10-Q and through the end of the fourth quarter of 2009, the trading price of our stock had experienced further reductions.
 
We completed Step 1 of the impairment test during the second quarter of 2009 and concluded that impairment existed. We finalized our Step 2 analysis during the third quarter of 2009. Consistent with the preliminary Step 2 analysis completed during the second quarter of 2009, we concluded that all of our goodwill was impaired. The resulting non-cash charge of $299.6 million was reported in our second quarter of 2009 results of operations. We had no such impairment charges during 2010 or 2008.
 
We amortize intangible assets, such as rights-of-way, licenses, and permits over their economic useful lives, unless the economic useful lives of the assets are indefinite. If an intangible asset’s economic useful life is determined to be indefinite, then that asset is not amortized. We consider factors such as the asset’s history, our plans for that asset, and the market for products associated with the asset when the intangible asset is acquired. We consider these same factors when reviewing the economic useful lives of our existing intangible assets as well. We review the economic useful lives of our intangible assets at least annually.
 
Environmental and Other Loss Contingencies.  We record liabilities for loss contingencies, including environmental remediation costs, when such losses are probable and can be reasonably estimated. Environmental costs are expensed if they relate to an existing condition caused by past operations with no future economic benefit. Estimates of projected environmental costs are made based upon internal and third-party assessments of contamination, available remediation technology, and environmental regulations. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties.
 
As a result of purchase accounting related to the Giant acquisition, the majority of our environmental obligations assumed in the acquisition of Giant are recorded on a discounted basis. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than other, the lower end of the range is used. Possible recoveries of some of these costs from other parties are not recognized in the financial statements until they become probable. Legal costs associated with environmental remediation are included as part of the estimated liability. We have $18.3 million accrued at December 31, 2010 for environmental obligations.


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Asset Retirement Obligations (“ARO”).  The estimated fair value of an ARO is based on the estimated current cost escalated by an inflation rate and discounted at a credit adjusted risk free rate. This liability is capitalized as part of the cost of the related asset and amortized using the straight-line method. The liability accretes until we settle the liability. Legally restricted assets have been set aside for purposes of settling certain of the ARO liabilities.
 
Financial Instruments and Fair Value.  We are exposed to various market risks, including changes in commodity prices. We use commodity future contracts, price swaps, and options to reduce price volatility, to fix margins for refined products, and to protect against price declines associated with our crude oil and blendstock inventories. All derivatives entered into by us are recognized as either assets or liabilities in the Consolidated Balance Sheets and those instruments are measured at fair value. We elected not to pursue hedge accounting treatment for these instruments for financial accounting purposes. Therefore, changes in the fair value of these derivative instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold using mark-to-market accounting.
 
Pension and Other Postretirement Obligations.  Pension and other postretirement plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends, and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and can have a significant effect on our pension and other postretirement liabilities and costs. A defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year, and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost.
 
Stock-Based Compensation.  The cost of the employee services received in exchange for an award of equity instruments awarded under the Western Refining Long-Term Incentive Plan is measured based on the grant date fair value of the award. The fair value of each share of restricted stock awarded is measured based on the market price at closing as of the measurement date and is amortized on a straight-line basis over the respective vesting periods.
 
Recent Accounting Pronouncements
 
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board or other standard setting bodies that may have an impact on our accounting and reporting. We believe that such recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have an impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations, and cash flows when implemented.


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Results of Operations
 
The following tables summarize our consolidated and operating segment financial data and key operating statistics for the three years ended December 31, 2010:
 
Consolidated
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Net sales(1)
  $ 7,965,053     $ 6,807,368     $ 10,725,581  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)(1)
    7,155,967       5,944,128       9,735,500  
Direct operating expenses (exclusive of depreciation and amortization)(1)
    444,531       486,164       532,325  
Selling, general, and administrative expenses
    84,175       109,697       115,913  
Goodwill and other impairment losses
    13,038       352,340        
Maintenance turnaround expense
    23,286       8,088       28,936  
Depreciation and amortization
    138,621       145,981       113,611  
                         
Total operating costs and expenses
    7,859,618       7,046,398       10,526,285  
                         
Operating income (loss)
  $ 105,435     $ (239,030 )   $ 199,296  
                         
 
 
(1) Excludes $3,294.0 million, $2,095.0 million, and $2,847.8 million of intercompany sales; $3,287.5 million, $2,088.8 million, and $2,831.6 million of intercompany cost of products sold; and $6.5 million, $6.2 million, and $16.2 million of intercompany direct operating expenses for the years ended December 31, 2010, 2009, and 2008, respectively.
 
Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009
 
Net Sales.  Net sales primarily consist of gross sales of refined products, lubricants, and merchandise, net of customer rebates or discounts, and excise taxes. Net sales for the year ended December 31, 2010 were $7,965.1 million, compared to $6,807.4 million for the year ended December 31, 2009, an increase of $1,157.7 million, or 17.0%. This increase was the result of increased sales from our refining, wholesale, and retail groups of $570.7 million, $502.0 million, and $85.0 million, respectively, net of intercompany transactions that eliminate in consolidation. The average sales price per barrel of refined products for all operating segments increased from $71.99 in 2009 to $93.18 million in 2010. This increase was partially offset by decreased sales volumes from 118.8 million barrels in 2009 to 117.1 million barrels in 2010, a decrease of 1.7 million barrels, or 1.4%.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased refined products, lubricants and merchandise for resale, and transportation and distribution costs. Cost of products sold was $7,156.0 million for the year ended December 31, 2010, compared to $5,944.1 million for the year ended December 31, 2009, an increase of $1,211.9 million, or 20.4%. This increase was primarily the result of increased cost of products sold from our refining, wholesale, and retail groups of $629.3 million, $499.9 million, and $82.7 million, respectively, net of intercompany transactions that eliminate in consolidation. Cost of products sold for the year ended December 31, 2009 included a non-cash LCM inventory recovery of $61.0 million. No such recovery occurred in 2010. The average cost per barrel of crude oil, feedstocks, and refined products for all operating segments increased from $65.60 in 2009 to $86.94 in 2010. Cost of products sold for the year ended December 31, 2009 includes $21.7 million in economic hedging losses previously reported as loss from derivative activities under other income (expense). We reclassified the prior year amount to conform to the current presentation. Cost of products sold for the year ended December 31, 2010 includes $9.4 million in economic hedging losses.


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Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include direct costs of labor, maintenance materials and services, transportation expenses, chemicals and catalysts, natural gas, utilities, insurance expense, property taxes, and other direct operating expenses. Direct operating expenses were $444.5 million for the year ended December 31, 2010, compared to $486.2 million for the year ended December 31, 2009, a decrease of $41.7 million, or 8.6%. Included in this decrease was $8.5 million related to the reversal of our December 2009 incentive bonus accrual. This decrease in direct operating expenses resulted from decreases of $40.1 million and $3.6 million partially offset by an increase of $2.0 million, in direct operating expenses of our refining, wholesale, and retail groups, respectively, net of intercompany transactions that eliminate in consolidation. Included within the decrease of $40.1 million in our refining group was a decrease of $23.4 million in direct operating expenses primarily resulting from cost-saving initiatives related to the fourth quarter 2009 consolidation of our Four Corners refining operations. This decrease was partially offset by certain costs associated with terminal operations at our Bloomfield facility. Accrued incentive bonus of $4.7 million was included in consolidated direct operating expenses for the year ended December 31, 2010.
 
In total, we reversed $14.7 million related to our December 2009 incentive bonus accrual including the $6.2 million reversal discussed below under selling, general, and administrative expenses for the year ended December 31, 2010. We consider the awarding of a bonus for any period to be discretionary and subject to not only the earnings during the bonus period, but also to the economic conditions and refining industry environment at the time the bonus is to be paid. Our first quarter 2010 results, coupled with our near-term forecasts of operating results and our expectations for the economy were such that we did not deem the pay-out of the previously accrued 2009 bonus prudent as such payment would not be in the best interests of the Company or our shareholders. On March 29, 2010, we determined that 2009 bonuses would not be paid. Accrued incentive bonus of $8.3 million was included in consolidated direct operating costs and selling, general, and administrative expenses for the year ended December 31, 2010 which had been substantially paid out by March 4, 2011.
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of corporate overhead, marketing expenses, public company costs, and stock-based compensation. Selling, general, and administrative expenses were $84.2 million for the year ended December 31, 2010, compared to $109.7 million for the year ended December 31, 2009, a decrease of $25.5 million, or 23.2%. Included in this decrease was $6.2 million related to the reversal of our December 2009 incentive bonus accrual. See direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2010 for additional discussion of the bonus accrual reversal. This decrease resulted from decreased expenses in our refining, wholesale, and retail groups of $15.8 million, $4.0 million, and $1.1 million respectively, and a $4.6 million decrease in corporate overhead.
 
The decrease of $4.6 million in corporate overhead was primarily caused by decreased professional and legal fees ($4.2 million). Accrued incentive bonus of $3.6 million was included in consolidated selling, general, and administrative expenses for the year ended December 31, 2010.
 
Goodwill and Other Impairment Losses.  As a result of our decision to permanently close our product distribution terminal in Flagstaff, Arizona during the third quarter of 2010, we completed an impairment analysis of the related long-lived assets and determined from this analysis that impairment existed. Accordingly, we recorded an impairment charge of $4.0 million primarily related to the Flagstaff long-lived and other assets. Also during 2010, we determined the existence of additional impairment related to certain of Bloomfield’s refinery assets and recorded a resulting non-cash charge of $9.1 million.
 
During 2009, we determined that our entire goodwill balance, which was previously reported under four of our six reporting units, was impaired. The total impact of this impairment was a non-cash charge of $299.6 million. Also during 2009, following our decision to indefinitely suspend the refining operations of our Bloomfield refinery, we completed an impairment analysis of the related long-lived and intangible assets and determined that impairment of certain of the Bloomfield refinery related assets existed and accordingly recorded a non-cash impairment charge of $52.8 million.
 
Maintenance Turnaround Expense.  Maintenance turnaround expense includes periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. During 2010, we incurred costs of $23.3 million in connection with a maintenance turnaround at the El Paso refinery. Primarily


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during the third and fourth quarters of 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter of 2010 at the El Paso refinery, and $1.2 million in connection with the anticipated 2010 turnaround at the Yorktown refinery, which was subsequently canceled.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2010 was $138.6 million compared to $146.0 million for the year ended December 31, 2009, a decrease of $7.4 million, or 5.1%. The majority of the decrease was due to differences in the timing of various assets reaching the end of their estimated useful lives.
 
Operating Income (Loss).  Operating income was $105.4 million for the year ended December 31, 2010, compared to an operating loss of $239.0 million for the year ended December 31, 2009, an increase of $344.4 million. This increase was primarily attributable to non-cash impairment losses of $352.3 million recorded in 2009 compared to $13.0 million in 2010, and decreased direct operating and selling, general, and administrative expenses along with decreased depreciation expense. The increase was partially offset by increased maintenance turnaround costs due to the maintenance turnaround completed in the first quarter of 2010.
 
Interest Income.  Interest income for the years ended December 31, 2010 and 2009 was $0.4 million and $0.2 million, respectively.
 
Interest Expense and Other Financing Costs.  Interest expense was $146.5 million (net of capitalized interest of $4.2 million) for the year ended December 31, 2010, compared to $121.3 million (net of capitalized interest of $6.4 million) for the year ended December 31, 2009, an increase of $25.2 million, or 20.8%. This increase was primarily attributable to a full year of interest expense and discount amortization on the Senior Secured and Convertible Senior Notes in 2010 compared to six months in 2009. This increase was partially offset by lower 2010 Term Loan interest expense resulting from the early retirement of a portion of our Term Loan in 2009.
 
Amortization of Loan Fees.  Amortization of loan fees for 2010 was $9.7 million compared to $6.9 million for 2009, an increase of $2.8 million, or 40.6%. This increase is primarily the result of additional deferred loan fees incurred during 2009 of $30.7 million for new debt and amendments to our Term Loan and our Revolving Credit Agreement. This increase was partially offset by the reduction in amortization expense resulting from the write-off of $9.0 million in unamortized loan fees in 2009 related to the early retirement of a portion of our Term Loan.
 
Write-off of Unamortized Loan Fees.  We made unscheduled principal payments on our Term Loan credit agreement primarily from the net proceeds of our 2009 debt and common stock offerings. As a result of the early retirement of a portion of our Term Loan, we wrote off $9.0 million in 2009 related to the portion of deferred financing costs associated with that portion of the Term Loan.
 
Provision for Income Taxes.  Our effective tax rate can be affected by any estimated tax credits that we plan to utilize for the year’s estimated tax provision. Generally, such tax credits will lower our tax expense and effective rate when we have positive earnings and increase our tax benefit and effective rate when we have losses. We recorded an income tax benefit of $26.1 million for the year ended December 31, 2010, using an estimated effective tax rate of 60.5%, as compared to the federal statutory rate of 35%. The effective tax rate was higher primarily due to the federal income tax credit available to small business refiners related to the production of ultra low sulfur diesel fuel.
 
We recorded an income tax benefit of $40.6 million for the year ended December 31, 2009, using an estimated effective tax rate of 44.3%, as compared to the federal statutory rate of 35%. The effective tax rate was higher primarily due to the federal income tax credit available to small business refiners related to the production of ultra low sulfur diesel fuel and the non-deductible goodwill impairment for federal tax reporting purposes.
 
Net Income (Loss).  We reported a net loss of $17.0 million for the year ended December 31, 2010, representing $0.19 net loss per share on weighted average diluted shares outstanding of 88.2 million. We reported a net loss of $350.6 million for the year ended December 31, 2009, representing $4.43 net loss per share on weighted average dilutive shares outstanding of 79.2 million. Our net loss for the year ended December 31, 2009 included a non-cash goodwill impairment charge of $299.6 million and a before-tax $20.0 million legal settlement charge. Similar charges were not included in our net loss for the year ended December 31, 2010.
 
See additional analysis under the Refining Segment, Wholesale Segment, and Retail Segment.


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Fiscal Year Ended December 31, 2009 Compared to Fiscal Year Ended December 31, 2008
 
Net Sales.  Net sales primarily consist of gross sales of refined products, lubricants, and merchandise, net of customer rebates or discounts, and excise taxes. Net sales for the year ended December 31, 2009 were $6,807.4 million, compared to $10,725.6 million for the year ended December 31, 2008, a decrease of $3,918.2 million, or 36.5%. This decrease was the result of decreased sales from our refining, wholesale, and retail groups of $3,231.8 million, $502.9 million, and $183.5 million, respectively, net of intercompany transactions that eliminate in consolidation. The average sales price per barrel of refined products for all operating segments decreased from $113.20 in 2008 to $71.99 in 2009. This decrease was partially offset by an increase in sales volumes. Our sales volume increased by 2.5 million barrels, or 2.1%, to 118.8 million barrels for 2009 compared to 116.3 million barrels for 2008.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased refined products, lubricants and merchandise for resale, and transportation and distribution costs. Cost of products sold was $5,944.1 million for the year ended December 31, 2009, compared to $9,735.5 million for the year ended December 31, 2008, a decrease of $3,791.4 million, or 38.9%. This decrease primarily was the result of decreased cost of products sold from our refining, wholesale, and retail groups of $3,128.4 million, $476.6 million, and $186.4 million, respectively, net of intercompany transactions that eliminate in consolidation. A non-cash LCM inventory write-down of $61.0 million was included in cost of products sold in 2008 versus a non-cash LCM inventory recovery of $61.0 million in 2009. The average cost per barrel of crude oil, feedstocks, and refined products for all operating segments decreased from $105.44 in 2008, to $65.60 in 2009. Cost of products sold for the year ended December 31, 2009 and 2008 includes $21.7 million in economic hedging losses and $11.4 million in economic hedging gains, respectively, previously reported as gain (loss) from derivative activities under other income (expense) in our Consolidated Statements of Operations. These prior year amounts were reclassified to conform to current presentation.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include direct costs of labor, maintenance materials and services, transportation expenses, chemicals and catalysts, natural gas, utilities, insurance expense, property taxes, and other direct operating expenses. Direct operating expenses were $486.2 million for the year ended December 31, 2009, compared to $532.3 million for the year ended December 31, 2008, a decrease of $46.1 million, or 8.7%. This decrease resulted from decreases of $33.0 million, $12.5 million, and $0.6 million in direct operating expenses of our refining, wholesale, and retail groups, respectively, net of intercompany transactions that eliminate in consolidation.
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of corporate overhead, marketing expenses, public company costs, and stock-based compensation. Selling, general, and administrative expenses were $109.7 million for the year ended December 31, 2009, compared to $115.9 million for the year ended December 31, 2008, a decrease of $6.2 million, or 5.3%. This decrease resulted from decreased expenses in our refining and wholesale groups of $1.5 million and $2.3 million, respectively, and a $3.2 million decrease in corporate overhead. These decreases were offset by increases of $0.9 million in our retail group.
 
The decrease of $3.2 million in corporate overhead was primarily caused by decreased personnel costs mainly related to decreased 401(k) contribution expense resulting from the allocation to the other operating segments ($4.4 million), incentive compensation ($3.2 million), decreased stock-based compensation ($2.6 million), and vacation expense ($1.8 million). These decreases were partially offset by increased professional and legal fees ($5.6 million) and increased information technology expenses ($2.6 million).
 
Goodwill and Other Impairment Losses.  During 2009, we determined that all of our goodwill was impaired. The total impact of this goodwill impairment was a non-cash charge of $299.6 million. Also during 2009, as a result of our decision to indefinitely suspend the refining operations of our Bloomfield refinery, we completed an impairment analysis of the related long-lived assets. We determined that impairment of certain of the Bloomfield refinery related long-lived and intangible assets existed and accordingly recorded a non-cash charge of $52.8 million related to this impairment. No impairment losses were recorded in 2008.


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Maintenance Turnaround Expense.  Maintenance turnaround expense includes periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. Primarily during the third and fourth quarters of 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter of 2010 at the El Paso refinery, and $1.2 million in connection with the planned turnaround in the third quarter of 2010 at the Yorktown refinery. During the year ended December 31, 2008, we performed a maintenance turnaround at the north side of the El Paso refinery at a cost of $28.9 million.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2009 was $146.0 million, compared to $113.6 million for the year ended December 31, 2008, an increase of $32.4 million, or 28.5%. The increase was due to the completion of various capital projects during the latter part of 2008 and 2009.
 
Operating Income (Loss).  Operating loss was $239.0 million for the year ended December 31, 2009, compared to operating income of $199.3 million for the year ended December 31, 2008, a decrease of $438.3 million. This decrease was primarily attributable to non-cash impairment losses of $352.3 million recorded in 2009 and decreased gross margins resulting from lower sales prices per barrel during 2009 without a corresponding decrease in the cost per barrel of crude.
 
Interest Income.  Interest income for the years ended December 31, 2009 and 2008, was $0.2 million and $1.8 million, respectively. The decrease was attributable to decreased balances of cash for investment as well as lower interest rates in 2009 compared to 2008.
 
Interest Expense and Other Financing Costs.  Interest expense was $121.3 million (net of capitalized interest of $6.4 million) for the year ended December 31, 2009, compared to $102.2 million (net of capitalized interest of $9.9 million) for the year ended December 31, 2008, an increase of $19.1 million or 18.7%. The increase is primarily attributable to higher effective interest rates in the latter half of 2009 versus 2008 offset by lower levels of outstanding debt.
 
Amortization of Loan Fees.  Amortization of loan fees for 2009 was $6.9 million, compared to $4.8 million for 2008. The increase is primarily the result of additional deferred loan fees incurred during 2009 of $30.7 million for new debt and amendments to our term and revolving loan agreements. This increase was partially offset by the reduction in amortization expense resulting from the write-off of $9.0 million in unamortized loan fees related to our Term Loan. On June 30, 2008, we entered into an amendment to our Term Loan Credit Agreement and incurred $22.4 million in loan fees. This increase was partially offset by the write-off of $10.9 million in unamortized loan fees incurred in May 2007.
 
Write-off of Unamortized Loan Fees.  During 2009, we expensed $9.0 million in deferred loan fees when we retired $912.7 million of our term debt earlier than scheduled with proceeds from our debt and stock offering. On June 30, 2008, we entered into an amendment to our Term Loan Credit Agreement and as a result, we recorded an expense of $10.9 million related to the write-off of deferred loan fees incurred in May 2007.
 
Provision for Income Taxes.  We recorded an income tax benefit of $40.6 million for the year ended December 31, 2009, using an estimated effective tax rate of 44.3%, as compared to the federal statutory rate of 35%. The effective tax rate was higher primarily due to the federal income tax credit available to small business refiners related to the production of ultra low sulfur diesel fuel and the non-deductible goodwill impairment for federal tax reporting purposes.
 
We recorded an income tax expense of $20.2 million for the year ended December 31, 2008, using an estimated effective tax rate of 24.0%, as compared to the federal statutory rate of 35%. The effective tax rate was lower primarily due to the federal income tax credit available to small business refiners related to the production of ultra low sulfur diesel fuel.
 
Net Income (Loss).  We reported a net loss of $350.6 million for the year ended December 31, 2009, representing $4.43 net loss per share on weighted average dilutive shares outstanding of 79.2 million. Our net loss for the year ended December 31, 2009 included a before tax $20.0 million legal settlement charge. Similar charges were not included in net income for the year ended December 31, 2008. For the year ended December 31, 2008, we


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reported net income of $64.2 million representing $0.94 net income per share on weighted average dilutive shares outstanding of 67.7 million.
 
The following tables set forth our summary and individual refining throughput and production data. All Refineries summary tables include summary throughput and production data for all of our refineries for the periods presented. Southwest Refineries summary tables present current and prior year operating and production results of our refining facilities operational as of December 31, 2010 for the periods presented. We do not allocate selling, general, and administrative expenses to the individual refineries or other related refinery operations.
 
Refining Segment (All Refineries and Related Operations)
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per barrel data)  
 
Net sales (including intersegment sales)
  $ 8,070,119     $ 6,608,075     $ 10,455,602  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)(1)
    7,439,826       5,919,499       9,653,681  
Direct operating expenses (exclusive of depreciation and amortization)
    335,869       375,690       418,628  
Selling, general, and administrative expenses
    20,155       36,021       37,561  
Goodwill and other impairment losses
    12,832       283,500        
Maintenance turnaround expense
    23,286       8,088       28,936  
Depreciation and amortization
    118,661       125,537       95,713  
                         
Total operating costs and expenses
    7,950,629       6,748,335       10,234,519  
                         
Operating income (loss)
  $ 119,490     $ (140,260 )   $ 221,083  
                         
Key Operating Statistics
                       
Total sales volume (bpd)(2)(7)
    248,785       258,259       258,013  
Total refinery production (bpd)(7)
    192,997       213,833       225,740  
Total refinery throughput (bpd)(3)(7)
    194,492       215,815       227,130  
Per barrel of throughput:
                       
Refinery gross margin(1)(4)
  $ 8.88     $ 8.74     $ 9.65  
Gross profit(4)
    7.21       7.15       8.50  
Direct operating expenses(5)
    4.73       4.77       5.04  


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Southwest Refineries (El Paso and Four Corners and Related Operations)
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per barrel data)  
 
Net sales (including intersegment sales)
  $ 6,321,322     $ 4,877,985       7,565,295  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)
    5,745,996       4,326,182       6,927,609  
Direct operating expenses (exclusive of depreciation and amortization)
    242,422       262,259       297,228  
Selling, general, and administrative expenses
    20,155       36,021       27,843  
Goodwill and other impairment losses
    12,832       125,936        
Maintenance turnaround expense
    23,286       6,898       28,936  
Depreciation and amortization
    72,886       78,732       53,905  
                         
Total operating costs and expenses
    6,117,577       4,836,028       7,335,521  
                         
Operating income
  $ 203,745     $ 41,957     $ 229,774  
                         
Key Operating Statistics
                       
Total sales volume (bpd)(2)
    189,613       184,108       180,940  
Total refinery production (bpd)
    149,007       150,411       154,295  
Total refinery throughput (bpd)(3)
    151,288       153,082       157,332  
Per barrel of throughput:
                       
Refinery gross margin(4)
  $ 10.42     $ 9.88     $ 11.07  
Gross profit(4)
    9.10       8.47       10.14  
Direct operating expenses(5)
    4.39       4.69       5.16  
 
All Refineries
 
                         
    Year Ended December 31,  
    2010(7)     2009     2008  
 
Refinery Product Yields (bpd)
                       
Gasoline
    102,927       113,364       114,876  
Diesel and jet fuel
    73,774       80,157       88,695  
Residuum
    4,899       5,504       5,711  
Other
    7,174       9,349       9,649  
                         
Liquid by-products
    188,774       208,374       218,931  
By-products (coke)
    4,223       5,459       6,809  
                         
Total
    192,997       213,833       225,740  
                         
Refinery Throughput (bpd)
                       
Sweet crude oil
    131,028       126,328       143,714  
Sour or heavy crude oil
    44,129       65,260       62,349  
Other feedstocks and blendstocks
    19,335       24,227       21,067  
                         
Total refinery throughput (bpd)
    194,492       215,815       227,130  
                         


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Southwest Refineries (El Paso and Four Corners)
 
                         
    Year Ended December 31,  
    2010     2009(6)     2008  
 
Refinery Product Yields (bpd)
                       
Gasoline
    81,953       82,540       82,279  
Diesel and jet fuel
    58,122       57,976       61,552  
Residuum
    4,899       5,504       5,711  
Other
    4,033       4,391       4,753  
                         
Total
    149,007       150,411       154,295  
                         
Refinery Throughput (bpd)
                       
Sweet crude oil
    125,259       124,443       128,423  
Sour crude oil
    14,007       17,601       16,985  
Other feedstocks and blendstocks
    12,022       11,038       11,924  
                         
Total refinery throughput (bpd)
    151,288       153,082       157,332  
                         
 
                         
    Year Ended December 31,  
El Paso Refinery
  2010     2009     2008  
 
Key Operating Statistics
                       
Refinery product yields (bpd):
                       
Gasoline
    65,740       65,160       62,557  
Diesel and jet fuel
    51,571       50,524       52,754  
Residuum
    4,899       5,504       5,711  
Other
    3,245       3,341       3,612  
                         
Total refinery production (bpd)
    125,455       124,529       124,634  
                         
Refinery throughput (bpd):
                       
Sweet crude oil
    104,119       99,680       100,130  
Sour crude oil
    14,007       17,601       16,985  
Other feedstocks and blendstocks
    9,051       9,184       9,454  
                         
Total refinery throughput (bpd)
    127,177       126,465       126,569  
                         
Total sales volume (bpd)(2)
    153,398       147,854       138,775  
Per barrel of throughput:
                       
Refinery gross margin(4)
  $ 9.37     $ 9.20     $ 9.45  
Direct operating expenses(5)
    3.50       3.60       4.07  
 


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    Year Ended December 31,  
Four Corners Refineries
  2010     2009(6)     2008  
 
Key Operating Statistics
                       
Refinery product yields (bpd):
                       
Gasoline
    16,213       17,380       19,722  
Diesel and jet fuel
    6,551       7,452       8,798  
Other
    788       1,050       1,141  
                         
Total refinery production (bpd)
    23,552       25,882       29,661  
                         
Refinery throughput (bpd):
                       
Sweet crude oil
    21,140       24,763       28,293  
Other feedstocks and blendstocks
    2,971       1,854       2,470  
                         
Total refinery throughput (bpd)
    24,111       26,617       30,763  
                         
Total sales volume (bpd)(2)
    36,215       36,254       42,165  
Per barrel of throughput:
                       
Refinery gross margin(4)
  $ 16.82     $ 15.17     $ 15.49  
Direct operating expenses(5)
    6.68       8.79       8.35  
 
                         
    Year Ended December 31,  
Yorktown Refinery
  2010(7)     2009     2008  
 
Key Operating Statistics
                       
Refinery Product Yields (bpd):
                       
Gasoline
    28,043       30,824       32,597  
Diesel and jet fuel
    20,926       22,181       27,143  
Other
    4,199       4,958       4,896  
                         
Liquid by-products
    53,168       57,963       64,636  
By-products (coke)
    5,647       5,459       6,809  
                         
Total refinery production (bpd)
    58,815       63,422       71,445  
                         
Refinery throughput (bpd):
                       
Sweet crude oil
    7,713       1,885       15,291  
Heavy crude oil
    40,274       47,659       45,364  
Other feedstocks and blendstocks
    9,777       13,189       9,143  
                         
Total refinery throughput (bpd)
    57,764       62,733       69,798  
                         
Total sales volume (bpd)(2)(7)
    59,172       74,151       77,073  
Per barrel of throughput:
                       
Refinery gross margin(1)(4)
  $ 3.49     $ 5.97     $ 6.43  
Direct operating expenses(5)
    5.93       4.95       4.75  
 
 
(1) Cost of products sold includes non-cash LCM adjustments of $(61.0) million and $61.0 million for 2009 and 2008, respectively, related to valuation of our Yorktown inventories to net realizable market values. These non-cash adjustments resulted in a corresponding increase of $0.78 and decrease of $0.73 in combined refinery gross margins for the years ended December 31, 2009 and 2008, respectively. These non-cash adjustments resulted in a corresponding increase of $2.66 and decrease of $2.39 in Yorktown’s refinery gross margins for the years ended December 31, 2009 and 2008, respectively.
 
(2) Includes sales of refined products sourced from our refinery production as well as refined products purchased from third parties.

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(3) Total refinery throughput includes crude oil, other feedstocks, and blendstocks.
 
(4) Refinery gross margin is a per barrel measurement calculated by dividing the difference between net sales and cost of products sold by our refineries’ total throughput volumes for the respective periods presented. Economic hedging gains and losses included in the combined refining segment gross margin are not allocated to the individual refineries. Cost of products sold does not include any depreciation or amortization. Refinery gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of products sold) can be reconciled directly to our statement of operations. Our calculation of refinery gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.
 
The following table reconciles combined gross profit for all refineries to combined gross margin for all refineries for the periods presented:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per barrel data)  
 
Net sales (including intersegment sales)
  $ 8,070,119     $ 6,608,075     $ 10,455,602  
Cost of products sold (exclusive of depreciation and amortization)
    7,439,826       5,919,499       9,653,681  
Depreciation and amortization
    118,661       125,537       95,713  
                         
Gross profit
    511,632       563,039       706,208  
Plus depreciation and amortization
    118,661       125,537       95,713  
                         
Refinery gross margin
  $ 630,293     $ 688,576     $ 801,921  
                         
Refinery gross margin per refinery throughput barrel(4)
  $ 8.88     $ 8.74     $ 9.65  
                         
Gross profit per refinery throughput barrel(4)
  $ 7.21     $ 7.15     $ 8.50  
                         
 
The following table reconciles gross profit for our Southwest refineries to combined gross margin for our Southwest refineries for the periods presented:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per barrel data)  
 
Net sales (including intersegment sales)
  $ 6,321,322     $ 4,877,985     $ 7,565,295  
Cost of products sold (exclusive of depreciation and amortization)
    5,745,996       4,326,182       6,927,609  
Depreciation and amortization
    72,886       78,732       53,905  
                         
Gross profit
    502,440       473,071       583,781  
Plus depreciation and amortization
    72,886       78,732       53,905  
                         
Refinery gross margin
  $ 575,326     $ 551,803     $ 637,686  
                         
Refinery gross margin per refinery throughput barrel(4)
  $ 10.42     $ 9.88     $ 11.07  
                         
Gross profit per refinery throughput barrel(4)
  $ 9.10     $ 8.47     $ 10.14  
                         
 
(5) Refinery direct operating expenses per throughput barrel is calculated by dividing direct operating expenses by total throughput volumes for the respective periods presented. Direct operating expenses do not include any depreciation or amortization, and combined refinery direct operating expenses include transportation and other related expenses not specific to a particular refinery.
 
(6) Until November 2009, Four Corners refining was comprised of two separate facilities; the Bloomfield refinery and the Gallup refinery. In late November 2009, we consolidated refining operations into the Gallup facility and indefinitely suspended refining operations at the Bloomfield refinery. We calculated total bpd refinery


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production, refinery throughput, and sales volume related to the Four Corners refineries by dividing by 365 days.
 
(7) In September 2010, we temporarily suspended refining operations at our Yorktown refinery. We calculated Yorktown total bpd refinery production and refinery throughput by dividing total volumes by 273 days. Total Yorktown sales volume includes refined product sales, following the temporary suspension, through December 31, 2010. We calculated Yorktown’s bpd sales volume by dividing total refinery sales volume by 365 days.
 
For our combined refining operating statistics, we calculated total bpd refinery sales volume, refinery production, refinery throughput, and refinery product yields by dividing all refineries’ operations by 365 days.
 
Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
 
Net Sales.  Net sales primarily consist of gross sales of refined petroleum products, net of customer rebates, discounts, and excise taxes. Net sales for the year ended December 31, 2010 were $8,070.1 million, compared to $6,608.1 million for the year ended December 31, 2009, an increase of $1,462.0 million, or 22.1%. This increase primarily resulted from an increase in the average per barrel sales price. The average sales price per barrel increased from $70.09 in 2009 to $88.87 in 2010. This increase was partially offset by a decrease in sales volume of 3.5 million barrels, or 3.7%, from 94.3 million barrels in 2009 to 90.8 million barrels in 2010.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of products sold for the year ended December 31, 2010 was $7,439.8 million, compared to $5,919.5 million for the year ended December 31, 2009, an increase of $1,520.3 million, or 25.7%. This increase was primarily the result of increased average costs of crude oil. The average cost per barrel increased from $58.49 in 2009 to $77.31 in 2010, an increase of 32.2%. Also contributing to this increase were increased finished product and blendstock purchases. Partially offsetting this increase were decreased crude purchase volumes. During 2010, we purchased 63.4 million barrels of crude oil compared to 69.5 million barrels in 2009, a decrease of 8.8% primarily related to the temporary suspension of refining operations at our Yorktown refinery. Refinery gross margin per throughput barrel increased from $8.74 in 2009 to $8.88 in 2010. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $7.21 in 2010 compared to $7.15 in 2009. Cost of products sold for the year ended December 31, 2009 includes $21.7 million in economic hedging losses previously reported as loss from derivative activities under other income (expense). The prior year amount was reclassified to conform to current presentation. Cost of products sold for the year ended December 31, 2010 includes $9.4 million in economic hedging losses.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our refineries, such as energy and utility costs, catalyst and chemical costs, periodic maintenance, labor, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $335.9 million for the year ended December 31, 2010, compared to $375.7 million for the year ended December 31, 2009, a decrease of $39.8 million, or 10.6%. This decrease primarily resulted from decreased personnel costs ($24.9 million), including the reversal of our 2009 incentive bonus accrual in the first quarter of 2010. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the fiscal year ended December 31, 2010 for additional discussion of the bonus accrual reversal. Also contributing to the decrease were decreased maintenance expenses ($7.1 million), decreased chemicals and catalyst purchases ($7.0 million), decreased electricity expense ($5.7 million), decreased insurance expense ($3.4 million), decreased outside support services ($2.5 million), and decreased professional, legal, and other expenses ($2.7 million). Partially offsetting these decreases were increased environmental expenses ($5.7 million), increased natural gas expense ($5.3 million), and increased property taxes ($4.0 million).
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of segment overhead, marketing expenses, and stock-based compensation. Selling, general, and administrative expenses were $20.2 million for the year ended December 31, 2010 compared to $36.0 million for the year ended December 31, 2009, a decrease of $15.8 million, or 43.9%. This decrease primarily resulted from decreases in personnel costs ($6.9 million), including the reversal of the 2009 incentive bonus accrual in the first quarter of 2010. See consolidated direct operating expenses (exclusive of depreciation and amortization) for the fiscal year


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ended December 31, 2010 for additional discussion of the bonus accrual reversal. Also contributing to the decrease were decreased marketing expenses ($2.5 million), decreased information technology expenses ($1.7 million), decreased professional, legal, and other expenses ($1.7 million), decreased bad debt expense ($1.5 million), and decreased environmental fines and penalties ($1.5 million).
 
Goodwill and Other Impairment Losses.  As a result of our decision to permanently close our product distribution terminal in Flagstaff, Arizona during the third quarter of 2010, we completed an impairment analysis of the related long-lived assets and determined from this analysis that impairment existed. Accordingly, we recorded an impairment charge of $3.8 million primarily related to the Flagstaff long-lived assets. Also during 2010, we determined the existence of additional impairment to certain of Bloomfield’s refinery assets and recorded a non-cash impairment charge of $9.1 million. During 2009, we determined that all of the goodwill in two of our three refining reporting units was fully impaired. The total impact of this impairment was a non-cash charge of $230.7 million. Also during 2009, as a result of our decision to indefinitely suspend the refining operations of our Bloomfield refinery, we completed an impairment analysis of the related long-lived and intangible assets and determined that impairment of certain of the Bloomfield refinery related assets existed and accordingly recorded a non-cash charge of $52.8 million related to this impairment.
 
Maintenance Turnaround Expense.  Maintenance turnaround expense includes planned periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. During the year ended December 31, 2010, we incurred costs of $23.3 million in connection with a turnaround in the first quarter of 2010 at the El Paso refinery. During the year ended December 31, 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter 2010 at the El Paso refinery, and $1.2 million related to the anticipated 2010 turnaround at the Yorktown refinery, which was subsequently canceled.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2010 was $118.7 million, compared to $125.5 million for the year ended December 31, 2009. The decrease was primarily due to differences in the timing of various assets reaching the end of their estimated useful lives.
 
Operating Income (Loss).  Operating income was $119.5 million for the year ended December 31, 2010, compared to an operating loss of $140.3 million for the year ended December 31, 2009, an increase of $259.8 million. This increase is primarily attributable to the 2009 goodwill impairment loss and higher 2009 asset impairment losses compared to 2010, decreased direct operating and selling, general, and administrative expenses, and decreased depreciation and amortization expense. These decreases were partially offset by increased maintenance turnaround expense in 2010 compared to 2009.
 
Fiscal Year Ended December 31, 2009, Compared to Fiscal Year Ended December 31, 2008
 
Net Sales.  Net sales primarily consist of gross sales of refined petroleum products, net of customer rebates, discounts, and excise taxes. Net sales for the year ended December 31, 2009 were $6,608.1 million, compared to $10,455.6 million for the year ended December 31, 2008, a decrease of $3,847.5 million, or 36.8%. This decrease primarily resulted from a decrease in the average price and sales volume of refined products. The average sales price per barrel decreased from $110.46 in 2008 compared to $70.09 in 2009. Our sales volume decreased by 0.2 million barrels, or 0.2%, to 94.3 million barrels for 2009 compared to 94.5 million barrels for 2008. Also contributing to this decrease was decreased production in the Four Corners refineries as a result of running less crude oil ($16.1 million).
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold primarily includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of products sold was $5,919.5 million for the year ended December 31, 2009, compared to $9,653.7 million for the year ended December 31, 2008, a decrease of $3,734.2 million, or 38.7%. This decrease was primarily the result of lower average costs and volume purchased of crude oil. The average cost per barrel decreased from $98.86 in 2008 to $58.49 in 2009. During 2009, we purchased 69.5 million barrels of crude oil compared to 74.6 million barrels in 2008, a decrease of 6.8%. Also contributing to this decrease were decreased finished product and blendstock purchases and economic hedging losses. LCM inventory reserve recoveries of $61.0 million decreased cost of products sold in 2009 compared to 2008 LCM inventory charges of $61.0 million


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that increased cost of products sold. These decreases were partially offset by an increase in the change in our LIFO reserve. Refinery gross margin per throughput barrel decreased from $9.65 in 2008 to $8.74 in 2009, reflecting lower refining margins. Gross profit per barrel, based on the closest comparable GAAP measure to refinery gross margin, was $7.15 in 2009 compared to $8.50 in 2008. Cost of products sold for the year ended December 31, 2008 and 2009 includes $11.4 million in economic hedging gains and $21.7 million in economic hedging losses, respectively, previously reported as gain (loss) from derivative activities under other income (expense). These prior year amounts were reclassified to conform to the current presentation.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our refineries, such as energy and utility costs, catalyst and chemical costs, periodic maintenance, labor, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $375.7 million for the year ended December 31, 2009, compared to $418.6 million for the year ended December 31, 2008, a decrease of $42.9 million, or 10.2%. This decrease primarily resulted from decreases in natural gas expense ($18.4 million), environmental expense primarily resulting from cost recoveries received during 2009 ($14.8 million), general maintenance ($9.8 million), property taxes primarily resulting from tax refunds from prior years taxes and revisions in property tax appraisal rolls ($6.0 million), outside support services ($2.8 million), insurance expense ($2.5 million), facilities leases ($1.7 million), and equipment rental ($1.5 million). These decreases were partially offset by increased chemicals and catalyst ($4.4 million), personnel costs ($4.3 million), electricity expenses ($3.3 million), and increased professional fees ($1.4 million).
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of segment overhead, marketing expenses, and stock-based compensation. Selling, general, and administrative expenses were $36.0 million for the year ended December 31, 2009, compared to $37.6 million for the year ended December 31, 2008, a decrease of $1.6 million, or 4.3%. This decrease resulted from decreased professional and legal fees ($7.1 million). This decrease was partially offset by increases in marketing expenses ($2.1 million), environmental penalties ($1.5 million), and bad debt expense ($1.6 million).
 
Goodwill and Other Impairment Losses.  During 2009, we determined that all of the goodwill in two of our three refining reporting units was fully impaired. The total impact of this impairment was a non-cash charge of $230.7 million. Also during 2009, as a result of our decision to indefinitely suspend the refining operations of our Bloomfield refinery, we completed an impairment analysis of the related long-lived and intangible assets. We determined that impairment of certain of the Bloomfield refinery related assets existed and accordingly recorded a non-cash charge of $52.8 million related to this impairment. No impairment losses were recorded in 2008.
 
Maintenance Turnaround Expense.  Maintenance turnaround expense includes periodic maintenance and repairs generally performed every two to six years, depending on the processing unit involved. During the year ended December 31, 2009, we incurred costs of $2.9 million in a crude unit shutdown and $4.0 million in connection with the planned turnaround in the first quarter of 2010 at the El Paso refinery, and $1.2 million in anticipation of a turnaround previously scheduled for the fall of 2010 at the Yorktown refinery. During the year ended December 31, 2008, we performed a maintenance turnaround at the north side of the El Paso refinery at a cost of $28.9 million.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2009 was $125.5 million, compared to $95.7 million for the year ended December 31, 2008. The increase was primarily due to the completion of several projects including the FCC hydrotreater, the sour water stripper, and a new laboratory at the El Paso refinery; the gasoline desulfurization project at the Yorktown refinery; and various other capital projects at our refineries.
 
Operating Income (Loss).  Operating loss was $140.3 million for the year ended December 31, 2009, compared to operating income of $221.1 million for the year ended December 31, 2008, a decrease of $361.4 million. This decrease primarily is attributable to an asset impairment loss recorded in the fourth quarter of 2009 related to the suspension of refining activities at the Bloomfield refinery and a goodwill impairment loss recorded in the second quarter of 2009, increased depreciation and amortization expense, and decreased refinery gross margins in 2009 compared to 2008.


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Wholesale Segment
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per gallon data)  
 
Statement of Operations Data
                       
Net sales (including intersegment sales)
  $ 2,470,586     $ 1,664,397     $ 2,279,541  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation amortization)
    2,383,931       1,579,910       2,168,707  
Direct operating expenses (exclusive of depreciation and amortization)
    48,222       51,775       64,273  
Selling, general, and administrative expenses
    12,638       16,566       18,915  
Goodwill impairment loss
          41,230        
Depreciation and amortization
    5,069       5,616       5,551  
                         
Total operating costs and expenses
    2,449,860       1,695,097       2,257,446  
                         
Operating income (loss)
  $ 20,726     $ (30,700 )   $ 22,095  
                         
Operating Data
                       
Fuel gallons sold (in thousands)
    1,009,786       823,207       706,864  
Fuel margin per gallon(1)
  $ 0.07     $ 0.07     $ 0.09  
Lubricant sales
  $ 102,200     $ 111,193     $ 163,679  
Lubricant margin(2)
    11.5 %     9.6 %     12.4 %
 
 
(1) Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and cost of fuel sales for our wholesale segment by the number of gallons sold. Fuel margin per gallon is a measure frequently used in the petroleum products wholesale industry to measure operating results related to fuel sales.
 
(2) Lubricant margin is a measurement calculated by dividing the difference between lubricant sales and lubricant cost of products sold by lubricant sales. Lubricant margin is a measure frequently used in the petroleum products wholesale industry to measure operating results related to lubricant sales.
 
The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per gallon data)  
 
Net sales:
                       
Fuel sales (including intersegment sales)
  $ 2,588,628     $ 1,749,431     $ 2,269,203  
Excise taxes included in fuel sales
    (250,550 )     (224,771 )     (193,634 )
Lubricant sales
    102,200       111,193       163,679  
Other sales (including intersegment sales)
    30,308       28,544       40,293  
                         
Net sales
  $ 2,470,586     $ 1,664,397     $ 2,279,541  
                         
Cost of products sold:
                       
Fuel cost of products sold
  $ 2,527,758     $ 1,692,177     $ 2,205,548  
Excise taxes included in fuel sales
    (250,550 )     (224,771 )     (193,634 )
Lubricant cost of products sold
    90,411       100,567       143,317  
Other cost of products sold
    16,312       11,937       13,476  
                         
Cost of products sold
  $ 2,383,931     $ 1,579,910     $ 2,168,707  
                         
Fuel margin per gallon
  $ 0.07     $ 0.07     $ 0.09  
                         


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Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
 
Net Sales.  Net sales consist primarily of sales of refined products net of excise taxes, lubricants, and freight. Net sales for the year ended December 31, 2010 were $2,470.6 million compared to $1,664.4 million for the year ended December 31, 2009, an increase of $806.2 million, or 48.4%. This increase was primarily due to an increase in the sales price of refined products, increased fuel sales volume, and increased freight billed. The average sales price per gallon of refined products increased from $2.13 in 2009 to $2.56 in 2010. Fuel sales volume increased from 823.2 million gallons in 2009 to 1,009.8 million gallons in 2010. Fuel sales volume for the year ended December 31, 2010 included 113.0 million gallons sold to our Retail group without comparable wholesale sales for the same period during 2009. During 2009, such sales of fuel were reported under our Refining group. This increase was partially offset by a decrease in lubricant sales volume. Lubricant sales volume decreased from 11.8 million gallons in 2009 to 10.7 million gallons in 2010.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of refined products net of excise taxes, lubricants, and delivery freight. Cost of products sold was $2,383.9 million for the year ended December 31, 2010, compared to $1,579.9 million for the year ended December 31, 2009, an increase of $804.0 million, or 50.9%. This increase was primarily due to increased delivery freight expenses and costs of refined products and purchased fuel volume. The average cost per gallon increased from $2.06 in 2009 to $2.50 in 2010. This increase was partially offset by a decrease in the purchased volume of lubricants.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our wholesale division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $48.2 million for the year ended December 31, 2010, compared to $51.8 million for the year ended December 31, 2009, a decrease of $3.6 million, or 6.9%. This decrease primarily resulted from decreases in personnel costs ($6.1 million). This decrease was partially offset by increased vehicle fuel costs ($1.8 million) and repairs and maintenance ($0.7 million).
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $12.6 million in December 31, 2010, compared to $16.6 million for the year ended December 31, 2009, a decrease of $4.0 million, or 24.1%. This decrease primarily resulted from decreases in personnel costs ($2.6 million), taxes, licenses, and fees ($0.3 million), outside services ($0.2 million), and bank fees ($0.2 million).
 
Goodwill Impairment Loss.  During 2009, we determined that all of the goodwill in our wholesale reporting unit was fully impaired. The total impact of the goodwill impairment for the year ended December 31, 2009 was a non-cash charge of $41.2 million. No impairment losses were recorded in 2010.
 
Depreciation and Amortization.  Depreciation and amortization was $5.1 million for the year ended December 31, 2010, compared to $5.6 million for the year ended December 31, 2009, a decrease of $0.5 million, or 8.9%.
 
Operating Income (Loss).  Operating income for the year ended December 31, 2010 was $20.7 million compared to an operating loss of $30.7 million for the year ended December 31, 2009, an increase of $51.4 million. This increase primarily resulted from a goodwill impairment loss in 2009, decreased direct operating expenses, decreased selling, general, and administrative expenses, and increased fuel and lubricant margins for the year ended December 31, 2010 compared to the same period in 2009.
 
Fiscal Year Ended December 31, 2009, Compared to Fiscal Year Ended December 31, 2008
 
Net Sales.  Net sales consist primarily of sales of refined products net of excise taxes, lubricants, and freight. Net sales for the year ended December 31, 2009, were $1,664.4 million, compared to $2,279.5 million for the year ended December 31, 2008, a decrease of $615.1 million, or 27.0%. This decrease was primarily due to a decrease in the sales price of refined products and decreased sales volume of lubricants. The average sales price per gallon of refined products decreased from $3.21 in 2008 to $2.13 in 2009. Lubricant sales volume decreased from 17.0 million gallons in 2008 to 11.8 million gallons for the same period in 2009. This decrease was partially offset by increased fuel volumes sold.


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Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of refined products net of excise taxes, lubricants, and delivery freight. Cost of products sold was $1,579.9 million for the year ended December 31, 2009, compared to $2,168.7 million for the year ended December 31, 2008, a decrease of $588.8 million, or 27.2%. This decrease was primarily due to decreased costs of refined products and decreased purchased volume of lubricants. The average cost per gallon decreased from $3.12 in 2008 to $2.06 in 2009. This decrease was partially offset by increased fuel volumes purchased.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our wholesale division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $51.8 million for the year ended December 31, 2009, compared to $64.3 million for the year ended December 31, 2008, a decrease of $12.5 million, or 19.4%. This decrease primarily resulted from decreases in fuel expense ($6.7 million), repairs and maintenance ($2.7 million), vehicle licenses and permits ($0.7 million), outside maintenance services ($0.7 million), trailer leases ($0.6 million), and utilities ($0.6 million).
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $16.6 million for the year ended December 31, 2009, compared to $18.9 million for the year ended December 31, 2008, a decrease of $2.3 million, or 12.2%. This decrease primarily resulted from decreases in personnel costs ($1.2 million), outside services ($0.5 million), utilities ($0.4 million), repairs and maintenance ($0.3 million), administration supplies ($0.3 million), and bank fees ($0.3 million). These decreases were partially offset by an increase in bad debt expense ($0.8 million).
 
Goodwill Impairment Loss.  During 2009, we determined that all of the goodwill in our wholesale reporting unit was fully impaired. The total impact of the goodwill impairment for the year ended December 31, 2009 was a non-cash charge of $41.2 million. No impairment losses were recorded in 2008.
 
Depreciation and Amortization.  Depreciation and amortization was $5.6 million for the years ended December 31, 2009 and 2008.
 
Operating Income (Loss).  Operating loss for the year ended December 31, 2009, was $30.7 million, compared to operating income of $22.1 million for the year ended December 31, 2008, a decrease of $52.8 million. This decrease primarily resulted from a goodwill impairment loss and decreased lubricant and fuel margins for the year ended December 31, 2009 compared to the same period in 2008. These decreases were partially offset by decreased direct operating expenses and decreased selling, general, and administrative expenses.


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Retail Segment
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per gallon data)  
 
Statement of Operations Data
                       
Net sales (including intersegment sales)
  $ 718,369     $ 629,938     $ 838,197  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)
    619,674       533,481       744,691  
Direct operating expenses (exclusive of depreciation and amortization)
    66,997       64,979       65,604  
Selling, general, and administrative expenses
    5,095       6,216       5,301  
Goodwill impairment loss
          27,610        
Depreciation and amortization
    10,245       9,820       8,479  
                         
Total operating costs and expenses
    702,011       642,106       824,075  
                         
Operating income (loss)
  $ 16,358     $ (12,168 )   $ 14,122  
                         
Operating Data
                       
Fuel gallons sold (in thousands)
    207,303       205,532       210,401  
Fuel margin per gallon(1)
  $ 0.19     $ 0.18     $ 0.18  
Merchandise sales
  $ 191,324     $ 189,096     $ 185,712  
Merchandise margin(2)
    28.5 %     28.4 %     27.4 %
Operating retail outlets at period end
    150       149       155  
 
 
(1) Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales and cost of fuel sales for our retail segment by the number of gallons sold. Fuel margin per gallon is a measure frequently used in the retail industry to measure operating results related to fuel sales.
 
(2) Merchandise margin is a measurement calculated by dividing the difference between merchandise sales and merchandise cost of products sold by merchandise sales. Merchandise margin is a measure frequently used in the convenience store industry to measure operating results related to merchandise sales.
 
The following table reconciles fuel sales and cost of fuel sales to net sales and cost of products sold:
 


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    Year Ended December 31,  
    2010     2009     2008  
    (In thousands, except per gallon data)  
 
Net sales:
                       
Fuel sales (including intersegment sales)
  $ 582,688     $ 489,033     $ 694,891  
Excise taxes included in fuel revenues
    (79,639 )     (71,998 )     (66,736 )
Merchandise sales
    191,324       189,096       185,712  
Other sales
    23,996       23,807       24,330  
                         
Net sales
  $ 718,369     $ 629,938     $ 838,197  
                         
Cost of products sold:
                       
Fuel cost of products sold
  $ 543,916     $ 451,485     $ 657,537  
Excise taxes included in fuel cost of products sold
    (79,639 )     (71,998 )     (66,736 )
Merchandise cost of products sold
    136,855       135,459       134,821  
Other cost of products sold
    18,542       18,535       19,069  
                         
Cost of products sold
    619,674       533,481       744,691  
                         
Fuel margin per gallon
  $ 0.19     $ 0.18     $ 0.18  
                         
 
Fiscal Year Ended December 31, 2010, Compared to Fiscal Year Ended December 31, 2009
 
Net Sales.  Net sales consist primarily of gross sales of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Net sales for the year ended December 31, 2010 were $718.4 million, compared to $629.9 million for the year ended December 31, 2009, an increase of $88.5 million, or 14.0%. This increase was primarily due to an increase in the sales price of gasoline and diesel fuel. The average sales price per gallon, including excise taxes, increased from $2.38 in 2009 to $2.81 in 2010.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Cost of products sold was $619.7 million for the year ended December 31, 2010, compared to $533.5 million for the year ended December 31, 2009, an increase of $86.2 million, or 16.2%. This increase was primarily due to increased costs of gasoline and diesel fuel. Average fuel cost per gallon, including excise taxes, increased from $2.20 in 2009 to $2.62 in 2010.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our retail division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $67.0 million for the year ended December 31, 2010, compared to $65.0 million for the year ended December 31, 2009, an increase of $2.0 million, or 3.1%. This increase was primarily due to increased bank fees primarily related to credit card sales ($1.8 million).
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $5.1 million for the year ended December 31, 2010, compared to $6.2 million for the year ended December 31, 2009, a decrease of $1.1 million, or 17.7%. This decrease was primarily due to decreased personnel costs ($0.6 million), insurance expense ($0.3 million), and environmental expense ($0.2 million).
 
Goodwill Impairment Loss.  During 2009, we determined that all of the goodwill in our retail reporting unit was fully impaired. The total impact of the goodwill impairment for the year ended December 31, 2009 was a non-cash charge of $27.6 million. No impairment losses were recorded in 2010.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2010 was $10.2 million compared to $9.8 million for the year ended December 31, 2009, an increase of $0.4 million, or 4.1%.

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Operating Income (Loss).  Operating income for the year ended December 31, 2010 was $16.4 million compared to an operating loss of $12.2 million for the year ended December 31, 2009, an increase of $28.6 million. This increase was primarily due to a goodwill impairment charge in 2009.
 
Fiscal Year Ended December 31, 2009, Compared to Fiscal Year Ended December 31, 2008
 
Net Sales.  Net sales consist primarily of gross sales of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Net sales for the year ended December 31, 2009, were $629.9 million, compared to $838.2 million for the year ended December 31, 2008, a decrease of $208.3 million, or 24.9%. This decrease was primarily due to a decrease in the sales price of gasoline and diesel fuel. The average sales price per gallon decreased from $3.30 in 2008 to $2.38 in 2009. This decrease was partially offset by increased merchandise sales.
 
Cost of Products Sold (exclusive of depreciation and amortization).  Cost of products sold includes costs of gasoline and diesel fuel net of excise taxes, general merchandise, and beverage and food products. Cost of products sold was $533.5 million for the year ended December 31, 2009, compared to $744.7 million for the year ended December 31, 2008, a decrease of $211.2 million, or 28.4%. This decrease was primarily due to decreased costs of gasoline and diesel fuel. Average fuel cost per gallon decreased from $3.13 in 2008 to $2.20 in 2009.
 
Direct Operating Expenses (exclusive of depreciation and amortization).  Direct operating expenses include costs associated with the operations of our retail division such as labor, repairs and maintenance, rentals and leases, insurance, property taxes, and environmental compliance costs. Direct operating expenses were $65.0 million for the year ended December 31, 2009, compared to $65.6 million for the year ended December 31, 2008, a decrease of $0.6 million, or 0.9%.
 
Selling, General, and Administrative Expenses.  Selling, general, and administrative expenses consist primarily of overhead and marketing expenses. Selling, general, and administrative expenses were $6.2 million for the year ended December 31, 2009, compared to $5.3 million for the year ended December 31, 2008, an increase of $0.9 million, or 17.0%.
 
Goodwill Impairment Loss.  During 2009, we determined that all of the goodwill in our retail reporting unit was impaired. The total impact of the goodwill impairment for the year ended December 31, 2009 was a non-cash charge of $27.6 million. No impairment losses were recorded in 2008.
 
Depreciation and Amortization.  Depreciation and amortization for the year ended December 31, 2009, was $9.8 million, compared to $8.5 million for the year ended December 31, 2008, an increase of $1.3 million, or 15.3%.
 
Operating Income (Loss).  Operating loss for the year ended December 31, 2009, was $12.2 million, compared to operating income of $14.1 million for the year ended December 31, 2008, a decrease of $26.3 million. This decrease was primarily due to a goodwill impairment loss. This decrease was partially offset by higher merchandise and fuel margins for the year ended December 31, 2009, compared to the same period in 2008.
 
Outlook
 
The weak global economy over the past two years has resulted in decreased demand for refined products. The decreased demand along with narrowing differentials between light and heavy crude oil prices negatively impacted our refining margins through the first quarter of 2010 and all of 2009. Beginning in the second quarter of 2010, our refining margins improved due to increased demand, primarily for diesel fuel. During the early part of 2011, our refining margins have continued to strengthen, partially due to increased gasoline crack spreads as we approach the spring 2011 driving season, continued strong diesel demand, and a supply/demand imbalance of WTI crude oil in the Mid-Continent, resulting in historically low prices for WTI crude oil relative to Brent crude oil. This is a positive development for us as all of our crude oil purchases are based on pricing tied to WTI.


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Liquidity and Capital Resources
 
Cash Flows
 
The following table sets forth our cash flows for the periods indicated:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In thousands)  
 
Cash flows provided by operating activities
  $ 134,456     $ 140,841     $ 285,575  
Cash flows used in investing activities
    (73,777 )     (115,361 )     (220,554 )
Cash flows used in financing activities
    (75,657 )     (30,407 )     (274,769 )
                         
Net decrease in cash and cash equivalents
  $ (14,978 )   $ (4,927 )   $ (209,748 )
                         
 
Cash Flows Provided By Operating Activities
 
Net cash provided by operating activities for the year ended December 31, 2010 was $134.5 million. The most significant providers of cash were adjustments to net loss for non-cash items such as depreciation and amortization ($138.6 million), amortization of original issue discount ($15.9 million), impairment losses ($13.0 million), amortization of loan fees ($9.7 million), and stock-based compensation ($5.9 million). The most significant users of cash were a net cash outflow from a change in operating assets and liabilities ($14.8 million), deferred income taxes ($16.8 million), and our net loss ($17.0 million).
 
Net cash provided by operating activities for the year ended December 31, 2009 was $140.8 million. The most significant providers of cash were adjustments to net loss for non-cash items such as goodwill and other impairment losses ($352.3 million), depreciation and amortization ($146.0 million), deferred income taxes ($9.4 million), the write-off of unamortized loan fees ($9.0 million), amortization of original issue discount ($7.1 million), amortization of loan fees ($6.9 million), and stock-based compensation ($4.7 million). The most significant users of cash were our net loss ($350.6 million), and a net cash outflow from a change in operating assets and liabilities ($44.0 million).
 
Net cash provided by operating activities for the year ended December 31, 2008 was $285.6 million. The most significant providers of cash were our net income ($64.2 million), adjustments to net income for non-cash items such as depreciation and amortization ($113.6 million), the write-off of unamortized loan fees ($10.9 million), deferred income taxes ($14.1 million), stock-based compensation ($7.7 million), and amortization of loan fees ($4.8 million). Also contributing to our cash flows from operating activities was a net cash inflow from a change in operating assets and liabilities ($70.3 million).
 
Cash Flows Used In Investing Activities
 
Net cash used in investing activities for the year ended December 31, 2010 was $73.8 million, mainly relating to capital expenditures of $78.1 million, including capitalized interest of $4.2 million. Total capital spending for 2010, excluding capitalized interest, included spending on the Mobile Source Air Toxics II, or MSAT II, project ($42.5 million), other improvement projects at our El Paso refinery ($5.7 million), and several other improvement and regulatory projects primarily at our Gallup and Yorktown refineries ($19.4 million). In addition, our capital spending included projects for our retail group ($4.9 million), our wholesale group ($0.7 million), and general corporate spending ($0.7 million).
 
Net cash used in investing activities for the year ended December 31, 2009 was $115.4 million, mainly relating to capital expenditures, including capitalized interest of $6.4 million. Capital spending for 2009, excluding capitalized interest, included spending on the low sulfur gasoline project ($41.3 million), the MSAT project ($19.5 million), improvement projects in conjunction with the 2010 maintenance turnaround ($6.4 million), the diesel hydrotreater unit revamp project ($3.9 million), and amine unit upgrade ($3.3 million) at our El Paso refinery; coker unit upgrades ($5.9 million), the MSAT project ($4.5 million), and the crude unit yield improvement project ($1.5 million) at our Yorktown refinery; and several other improvement and regulatory projects for our refining


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group ($17.6 million). In addition, our total capital spending included projects for our retail group ($3.4 million), our corporate group ($1.4 million), and our wholesale group ($0.9 million).
 
Net cash used in investing activities for the year ended December 31, 2008 was $220.6 million, mainly relating to capital expenditures, including capitalized interest of $9.9 million. Capital spending for 2008, excluding capitalized interest, included spending on the low sulfur gasoline project ($99.4 million), improvement projects in conjunction with the 2008 maintenance turnaround ($22.7 million), the naphtha hydrotreating unit ($8.6 million), the construction of a new laboratory ($5.1 million), and the acid and sulfur gas facilities ($1.2 million) at our El Paso refinery; the low sulfur gasoline project ($23.4 million), improvements to the laboratory and fire station ($2.4 million), the ultraformer blowdown stack ($2.3 million), and coker unit electrical infrastructure ($1.9 million) at our Yorktown refinery; and several other improvement and regulatory projects for our refining group ($25.0 million). In addition, our total capital spending included projects for our retail group ($7.9 million), our corporate group ($6.8 million), and our wholesale group ($5.7 million).
 
Cash Flows Used In Financing Activities
 
Net cash used in financing activities for the year ended December 31, 2010 was $75.7 million. Cash used in financing activities for 2010 included a net decrease to our Revolving Credit Agreement ($50.0 million), principal payments on our Term Loan ($13.0 million), and deferred financing costs ($12.7 million).
 
Net cash used in financing activities for the year ended December 31, 2009 was $30.4 million. Cash used in financing activities for 2009 included principal payments on our Term Loan ($925.7 million), deferred financing costs ($11.7 million), a net decrease to our Revolving Credit Agreement ($10.0 million), and the repurchases of common stock ($0.6 million) to cover payroll withholding taxes for certain employees in connection with the vesting of restricted shares awarded under the Western Refining Long-Term Incentive Plan. These decreases in cash were significantly offset by the net proceeds from the issuance of our Senior Secured Notes ($538.2 million), our Convertible Senior Notes ($209.0 million), and common stock ($170.4 million).
 
Net cash used in financing activities for the year ended December 31, 2008 was $274.8 million. Cash used in financing activities for 2008 included a net decrease to our Revolving Credit Agreement ($230.0 million), deferred financing costs ($22.4 million), principal payments on our Term Loan ($13.0 million), dividends paid ($8.2 million), and the repurchases of common stock ($1.2 million) to cover payroll withholding taxes for certain employees in connection with the vesting of restricted shares awarded under the Western Refining Long-Term Incentive Plan.
 
Working Capital
 
Our primary sources of liquidity are cash generated from our operating activities, existing cash balances, and our Revolving Credit Agreement. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses. The improved refining margin environment during 2010, compared to the fourth quarter of 2009, positively impacted our earnings and cash flows. Our refining gross margin increased from $5.35 per throughput barrel in the fourth quarter of 2009 to $8.88 per throughput barrel for the year ended December 31, 2010. Refining margins were extremely volatile throughout 2009. For example, our refining margin per throughput barrel decreased from $13.59 in the first quarter of 2009 to $9.47, $7.28, and $5.35 in the second, third, and fourth quarters of 2009, respectively. These changes in refining margins are attributable to the spread between crude oil and refined product prices. If our margins deteriorate significantly, or if our earnings and cash flows suffer for any other reason, we could be unable to comply with the financial covenants set forth in our credit facilities (described below). If we fail to satisfy these covenants, we could be prohibited from borrowing for our working capital needs and issuing letters of credit, which would hinder our ability to purchase sufficient quantities of crude oil to operate our refineries at planned rates. To the extent that we are unable to generate sufficient cash flows from operations, or if we are unable to borrow or issue letters of credit under the revolving credit facility, we would need to seek additional financing, if available, in order to operate our business.
 
We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of the remaining balance on our Term Loan. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt


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financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all.
 
In addition, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors described in Part I. — Item 1A. Risk Factors elsewhere in this report.
 
Working capital at December 31, 2010 was $272.7 million, consisting of $825.7 million in current assets and $553.0 million in current liabilities. Working capital at December 31, 2009 was $311.3 million consisting of $944.2 million in current assets and $632.9 million in current liabilities. In addition, at December 31, 2010, the gross availability under the Revolving Credit Agreement was $624.0 million determined based on an advance rate formula tied to our accounts receivable and inventory levels. As of December 31, 2010, we had net availability under the Revolving Credit Agreement of $335.6 million due to $288.4 million in letters of credit outstanding and no outstanding borrowings. On February 25, 2011, the gross availability under the Revolving Credit Agreement was $650.3 million pursuant to the borrowing base. On February 25, 2011, we had net availability under the Revolving Credit Agreement of $192.3 million due to $273.0 million in letters of credit outstanding and $185.0 million in direct borrowings. Our available cash balance as of February 25, 2011 was $39.1 million.
 
Indebtedness
 
Senior Secured Notes.  In June 2009, we issued two tranches of Senior Secured Notes under an indenture dated June 12, 2009. The first tranche consisted of $325.0 million in aggregate principal amount of 11.25% Senior Secured Notes (the “Fixed Rate Notes”). The second tranche consisted of $275.0 million Senior Secured Floating Rate Notes (the “Floating Rate Notes,” and together with the Fixed Rate Notes, the “Senior Secured Notes”). The Fixed Rate Notes pay interest semi-annually in cash in arrears on June 15 and December 15 of each year at a rate of 11.25% per annum and will mature on June 15, 2017. We may redeem the Fixed Rate Notes at our option beginning on June 15, 2013 through June 14, 2014 at a premium of 5.625%; from June 15, 2014 through June 14, 2015 at a premium of 2.813%; and at par thereafter. As of December 31, 2010, the fair value of the Fixed Rate Notes was $347.8 million.
 
The Floating Rate Notes pay interest quarterly at a per annum rate, reset quarterly, equal to three-month LIBOR (subject to a LIBOR floor of 3.25%) plus 7.50% and will mature on June 15, 2014. The interest rate on the Floating Rate Notes as of December 31, 2010 was 10.75%. We may redeem the Floating Rate Notes at our option beginning on December 15, 2011 through June 14, 2012 at a premium of 5.0%; from June 15, 2012 through June 14, 2013 at a premium of 3.0%; and at a premium of 1.0% thereafter. The fair value of the Floating Rate Notes was $291.5 million at December 31, 2010. We are amortizing the original issue discounts using the effective interest rate method over the life of the notes. We used the combined proceeds from the issuance and sale of the Senior Secured Notes to repay a portion of the outstanding indebtedness under the Term Loan Credit Agreement (“Term Loan”). Proceeds from the issuance of the Fixed Rate Notes were $290.7 million, net of an original issue discount of $27.8 million and underwriting discounts of $6.5 million. Proceeds from the issuance of the Floating Rate Notes were $247.5 million, net of original issue discount of $22.0 million and underwriting discounts of $5.5 million. We paid $2.1 million in other financing costs related to the Senior Secured Notes in 2009.
 
The Senior Secured Notes are guaranteed by all of our domestic restricted subsidiaries in existence on the date the Senior Secured Notes were issued. The Senior Secured Notes will also be guaranteed by all future wholly-owned domestic restricted subsidiaries and by any restricted subsidiary that guarantees any of our indebtedness under credit facilities that are secured by a lien on the collateral securing the Senior Secured Notes. The Senior Secured Notes are also secured on a first priority basis, equally and ratably with our Term Loan and any future other pari passu secured obligation, by the collateral securing the Term Loan, which consists of our fixed assets, and on a second priority basis, equally and ratably with the Term Loan and any future other pari passu secured obligation, by the collateral securing the Revolving Credit Agreement, which consists of our cash and cash equivalents, trade accounts receivables, and inventory.
 
The indenture governing the Senior Secured Notes contains covenants that limit our (and most of our subsidiaries’) ability to, among other things: (i) pay dividends or make other distributions in respect of our capital stock or make other restricted payments; (ii) make certain investments; (iii) sell certain assets; (iv) incur additional


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debt or issue certain preferred shares; (v) create liens on certain assets to secure debt; (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; (vii) restrict dividends or other payments from restricted subsidiaries; and (viii) enter into certain transactions with our affiliates. These covenants are subject to a number of important limitations and exceptions. The indenture governing the Senior Secured Notes also provides for events of default, which, if any of them occur, would permit or require the principal, premium, if any, and interest on all then outstanding Senior Secured Notes to be due and payable immediately.
 
We may issue additional notes from time to time pursuant to the indenture governing the Senior Secured Notes.
 
Convertible Senior Notes.  We issued and sold $215.5 million in aggregate principal amount of our 5.75% Senior Convertible Notes due 2014 (the “Convertible Senior Notes”) during June and July 2009. The Convertible Senior Notes are unsecured and pay interest semi-annually in arrears at a rate of 5.75% per year beginning on December 15, 2009. The Convertible Senior Notes will mature on June 15, 2014. The initial conversion rate for the Convertible Senior Notes is 92.5926 shares of common stock per $1,000 principal amount of Convertible Senior Notes (equivalent to an initial conversion price of approximately $10.80 per share of common stock). In lieu of delivery of shares of common stock in satisfaction of our obligation upon conversion of the Convertible Senior Notes, we may elect to settle conversions entirely in cash or by net share settlement. Proceeds from the issuance of the Convertible Senior Notes of $209.0 million, net of underwriting discounts of $6.5 million, were used to repay a portion of outstanding indebtedness under the Term Loan. Issuers of convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are required to separately account for the liability and equity (conversion feature) components of the instruments in a manner reflective of the issuer’s nonconvertible debt borrowing rate. The borrowing rate that we used to determine the liability and equity components of the Convertible Senior Notes was 13.75%. We paid $0.5 million in other financing costs related to the Convertible Senior Notes. We valued the conversion feature at June 30, 2009 at $60.9 million and recorded additional paid-in capital of $36.3 million, net of deferred income taxes of $22.6 million and transaction costs of $2.0 million, related to the equity portion of this convertible debt in 2009. The discount on the Convertible Senior Notes is amortized using the effective interest method through maturity on June 15, 2014. As of December 31, 2010, the fair value of the Convertible Senior Notes was $275.5 million and the if-converted value is less than the principal amount.
 
Term Loan Credit Agreement.  The Term Loan has a maturity date of May 30, 2014. The Term Loan is secured on a first priority basis, together with the Senior Secured Notes and any future other pari passu secured obligations, by our fixed assets, and on a second priority basis, together with the Senior Secured Notes and any future other pari passu secured obligations, by the collateral securing the Revolving Credit Agreement, which consists of our cash and cash equivalents, trade accounts receivable, and inventory. The Term Loan provides for principal payments on a quarterly basis of $13.0 million annually until March 31, 2014, with the remaining balance due on the maturity date. We made principal payments on the Term Loan of $13.0 million in 2010, $925.7 million in 2009, primarily from the net proceeds of the debt and common stock offerings in June and July 2009, and $13.0 million during 2008. Since 2009, interest rates under the Term Loan are equal to LIBOR (subject to a floor of 3.25%) plus 7.50%. The average interest rates under the Term Loan for 2010 and 2009 were 10.75% and 8.67%, respectively. As of December 31, 2010, the interest rate under the Term Loan was 10.75%. We amended the Term Loan during the second and fourth quarters of 2009 in connection with the new debt offerings and to modify certain financial covenants. To effect these amendments, we paid $3.4 million in amendment fees. As a result of the partial paydown of the Term Loan in June 2009, we expensed $9.0 million during the second quarter of 2009 to write-off a portion of the unamortized loan fees related to the Term Loan. At December 31, 2010, the fair value of the Term Loan was $346.9 million.
 
Revolving Credit Agreement.  On December 23, 2010, we completed an amendment to the Revolving Credit Agreement resulting in, among other items, the extension of the maturity of a portion of the commitments thereunder to January 1, 2015. The amended Revolving Credit Agreement included commitments of $800.0 million composed of a $145.0 million tranche that matures on May 31, 2012 and a $655.0 million tranche that matures on January 1, 2015. The Revolving Credit Agreement is secured on a first priority basis by certain cash and cash equivalents, trade accounts receivable, and inventory, and on a second priority basis by the collateral securing the Term Loan, the Senior Secured Notes, and any future other pari passu secured obligations, which consist of the Company’s fixed assets. The Revolving Credit Agreement can be used to finance working capital and capital


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expenditures, refinance our existing indebtedness and that of our subsidiaries, and for other general corporate purposes; and also provides for letters of credit and swing line loans. The Revolving Credit Agreement is an asset-based facility with the borrowing base capacity primarily dependent on our eligible receivables and inventory. Interest rates for the $145.0 million tranche vary based on our consolidated leverage ratio and range from 3.75% to 4.50% over LIBOR or 2.75% to 3.50% over the Base Rate (as defined in the Revolving Credit Agreement). Interest rates for the $655.0 million tranche vary based on our excess borrowing base capacity under the Revolving Credit Agreement and range from 3.00% to 3.75% over LIBOR or 2.00% to 2.75% over the Base Rate. As of December 31, 2010, the gross availability under the Revolving Credit Agreement was $624.0 million. As of December 31, 2010, we had net availability under the Revolving Credit Agreement of $335.6 million due to $288.4 million in letters of credit outstanding. The average interest rates under the Revolving Credit Agreement for 2010 and 2009 were 6.15% and 5.20%, respectively. At December 31, 2010, there were no outstanding borrowings under the Revolving Credit Agreement. Among other amendments, the 2010 amendment replaced financial maintenance covenants with a fixed charge coverage ratio covenant that applies only when unused availability falls below a specified level. We incurred $12.7 million in fees related to the Revolving Credit Agreement amendment in 2010. We also amended the Revolving Credit Agreement during the second and fourth quarters of 2009 in connection with the new debt offerings and to modify certain of the financial covenants. We incurred $5.6 million in fees related to these amendments.
 
As a result of the 2009 amendment, our Revolving Credit Agreement required a structure mandating that all receipts be swept daily to reduce borrowings outstanding under the Revolving Credit Agreement. This arrangement, combined with the existence of a material adverse change clause in the Revolving Credit Agreement, required outstanding borrowings under the Revolving Credit Agreement to be classified as a current liability. As a result of the 2010 amendment, going forward, the cash dominion requirement will only be in effect if the excess availability under the Revolving Credit Agreement falls below a certain threshold.
 
Guarantors of the Term Loan and the Revolving Credit Agreement.  The Term Loan and the Revolving Credit Agreement (together, the “Agreements”) are guaranteed, on a joint and several basis, by subsidiaries of Western Refining, Inc. No amounts have been recorded for these guarantees.
 
Certain Covenants.  The Agreements contain certain covenants, including limitations on debt, investments, and dividends. The Term Loan contains financial covenants relating to minimum interest coverage and maximum leverage and, for certain periods in 2010 through September 30, 2010, minimum EBITDA. We were in compliance with all applicable covenants set forth in the Term Loan at December 31, 2010. The following table sets forth the financial covenant requirements for minimum consolidated interest coverage (as defined therein), and maximum consolidated leverage (as defined therein) under the Term Loan by quarter:
 
         
    Minimum
   
    Consolidated
  Maximum
    Interest Coverage
  Consolidated
    Ratio   Leverage Ratio
 
December 31, 2010 and March 31, 2011
  1.50 to 1.00   5.25 to 1.00
June 30, 2011 and thereafter
  2.00 to 1.00   4.50 to 1.00
 
Letters of Credit
 
The Revolving Credit Agreement provides for the issuance of letters of credit. We issue and cancel letters of credit on a periodic basis depending upon our needs. At December 31, 2010, there were $288.4 million of irrevocable letters of credit outstanding, primarily issued to crude oil suppliers under the Revolving Credit Agreement.
 
Capital Spending
 
Capital expenditures totaled $78.1 million for the year ended December 31, 2010, and included the MSAT II project at El Paso and several other improvement and regulatory projects for our refining group. In addition, our total capital spending included several smaller projects for our wholesale group, our retail group, and our corporate group. Capital expenditures also included $4.2 million of capitalized interest for 2010.


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Our capital expenditure budget for 2011 is $62.2 million, of which $52.5 million is for our refining group, $1.4 million is for our wholesale group, $6.3 million is for our retail group, and $2.0 million is for other general projects. The following table summarizes the spending allocation between sustaining, discretionary, and regulatory projects for 2011:
 
         
    2011  
    (In thousands)  
 
Sustaining
  $ 20,575  
Discretionary
    10,550  
Regulatory
    31,118  
         
Total
  $ 62,243  
         
 
Sustaining Projects.  Sustaining maintenance capital expenditures are those related to minor replacement of assets, refurbishing and replacement of components, fire protection, process safety management, and other recurring and safety related capital expenditures.
 
Discretionary Projects.  Discretionary project capital expenditures are those driven primarily by the economic returns that such projects can generate for us.
 
Regulatory Projects.  Regulatory projects are undertaken to comply with various regulatory requirements, including those related to environmental, health, and safety matters. Our low sulfur fuel and low benzene gasoline projects are regulatory investments, driven primarily by fuels regulations. We completed our capital project to comply with the EPA’s low sulfur gasoline regulations during 2010. Our Gallup and Yorktown refineries require no further regulatory spending to meet the EPA’s ultra low sulfur diesel standards. The deadline for compliance with the final phase of the ultra low sulfur diesel regulations to reduce sulfur in locomotive and marine diesel is June 2012 and affects our El Paso refinery only. EPA regulations allow the one-time use of credits to extend the June 2012 deadline by up to 24 months. Low sulfur credits purchased in 2010 will allow our El Paso refinery to continue producing 500 ppm sulfur locomotive diesel until early 2014. We are evaluating the need for a capital project to produce 15 ppm locomotive diesel after early 2014.
 
All of our refineries are required to meet the new Mobile Source Air Toxics, or MSAT II, regulations to reduce the benzene content of gasoline. Under the MSAT II regulations, benzene in the finished gasoline pool must be reduced to an annual average of 0.62 volume percent by 2011 with or without the purchase of credits. Beginning on July 1, 2012, each refinery must also average 1.30 volume percent benzene without the use of credits. As of December 31, 2010, we have expended $62.0 million to comply with MSAT II regulations at our El Paso refinery. A capital project for $2.0 million or less at our Gallup refinery is currently anticipated to meet the 1.30 volume percent requirement. Our Yorktown refinery currently meets the 1.30 volume percent benzene requirement and intends to rely on credits to comply with the 0.62 volume percent requirement.
 
Based on current information, we estimate the total remaining capital expenditures necessary to address the EPA Initiative issues at El Paso would be approximately $21.2 million for NOx emission controls on heaters and boilers and will occur from 2011 through 2013. Based on current information and the 2009 NMED Amendment and favorably negotiating a revision to reflect the indefinite suspension of refining operations at our Bloomfield facility, we estimate the total remaining capital expenditures that may be required pursuant to the 2009 NMED Amendment to address the EPA Initiative issues at Gallup would be $17.6 million and will occur in 2011 and 2012. These capital expenditures will primarily be for installation of emission controls on the heaters, boilers, and fluid catalytic cracking unit, and for reducing sulfur in fuel gas to reduce emissions of sulfur dioxide and NOx and particulate matter from our Gallup refinery. See Item 1. Business — Governmental Regulation.


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The actual capital expenditures for the regulatory projects described above for the past three years are summarized in the table below:
 
                         
    2010     2009     2008  
    (In millions)  
 
MSAT II gasoline
  $ 43     $ 20     $  
EPA Initiative Projects
                23  
                         
Total
  $ 43     $ 20     $ 23  
                         
 
The estimated capital expenditures for the regulatory projects described above and for other regulatory requirements for the next three years are summarized in the table below:
 
                         
    2011     2012     2013  
    (In millions)  
 
MSAT II gasoline
  $ 3     $ 1     $  
EPA Initiative Projects
    12       21        
Ultra low sulfur non-road diesel
          5       20  
Various other projects
    16       7       8  
                         
Total
  $ 31     $ 34     $ 28  
                         
 
Contractual Obligations and Commercial Commitments
 
Information regarding our contractual obligations of the types described below as of December 31, 2010, is set forth in the following table:
 
                                         
    Payments Due by Period  
Contractual Obligations
  Totals     2011     2012 and 2013     2014 and 2015     2016 and Beyond  
    (In thousands)  
 
Long-term debt obligations(1)
  $ 1,639,436     $ 173,705     $ 240,531     $ 846,878     $ 378,322  
Capital lease obligations
                             
Operating lease obligations
    94,505       16,059       23,718       16,315       38,413  
Purchase obligations(2)
    4,774,194       631,589       1,097,611       1,014,998       2,029,996  
Environmental reserves(3)
    23,288       11,095       1,601       1,265       9,327  
Other obligations(4)(5)
    310,557       34,192       44,636       33,718       198,011  
                                         
Total obligations(6)
  $ 6,841,980     $ 866,640     $ 1,408,097     $ 1,913,174     $ 2,654,069  
                                         
 
 
(1) Includes minimum principal payments and interest calculated using interest rates at December 31, 2010.
 
(2) Purchase obligations include agreements to buy crude oil and other raw materials. Amounts included in the table were calculated using the pricing at December 31, 2010, multiplied by the contract volumes.
 
(3) As of December 31, 2010, the discounted environmental reserve related to these liabilities totaled $18.3 million. Our environmental liabilities are discussed in Note 21, Contingencies, in the Notes to Consolidated Financial Statements elsewhere in this annual report.


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(4) Other commitments include agreements for sulfuric acid regeneration and sulfur gas processing, throughput and distribution, storage services, barges, and professional consulting. The minimum payment commitments are included in the table.
 
(5) We are obligated to make future expenditures related to our pension and postretirement obligations. These payments are not fixed and cannot be reasonably determined beyond 2018. As a result, our obligations beyond 2018 related to these plans are not included in the table. Our pension and postretirement obligations are discussed in Note 15, Retirement Plans, in the Notes to Consolidated Financial Statements elsewhere in this annual report.
 
(6) As of December 31, 2010, we have no uncertain tax positions or related liabilities recorded.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements.


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Item 7A.   Quantitative and Qualitative Disclosure About Market Risk
 
Changes in commodity prices and interest rates are our primary sources of market risk.
 
Commodity Price Risk
 
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refinery operations. Our financial results can be affected significantly by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline, and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels, and governmental regulatory initiatives. Our risk management strategy identifies circumstances in which we may utilize the commodity futures market to manage risk associated with these price fluctuations.
 
In order to manage the uncertainty relating to inventory price volatility, we have generally applied a policy of maintaining inventories at or below a targeted operating level. In the past, circumstances have occurred, such as turnaround schedules or shifts in market demand that have resulted in variances between our actual inventory level and our desired target level. We may utilize the commodity futures market to manage these anticipated inventory variances.
 
We maintain inventories of crude oil, other feedstocks and blendstocks, and refined products, the values of which are subject to wide fluctuations in market prices driven by worldwide economic conditions, regional and global inventory levels, and seasonal conditions. At December 31, 2010, we held approximately 5.7 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $58.39 per barrel. At December 31, 2010, aggregated LIFO costs exceeded the current cost of our crude oil, refined product, and other feedstock and blendstock inventories by $173.5 million. At December 31, 2009, we held approximately 6.3 million barrels of crude oil, refined product, and other inventories valued under the LIFO valuation method with an average cost of $56.32 per barrel. At December 31, 2009, aggregated LIFO costs exceeded the current cost of our crude oil, refined product, and other feedstock and blendstock inventories by $126.4 million.
 
All commodity futures contracts, price swaps, and options are recorded at fair value and any changes in fair value between periods are recorded under cost of products sold in our Consolidated Statements of Operations.
 
We selectively utilize commodity derivatives to manage our price exposure to inventory positions or to fix margins on certain future sales volumes. The commodity derivative instruments may take the form of futures contracts, price swaps, or options and are entered into with counterparties that we believe to be creditworthy. We elected not to pursue hedge accounting treatment for these instruments for financial accounting purposes. Therefore, changes in the fair value of these derivative instruments are included in income in the period of change. Net gains or losses associated with these transactions are reflected within cost of products sold at the end of each period. For the years ended December 31, 2010 and 2009, we had $9.4 million and $21.7 million, respectively, in net losses settled or accounted for using mark-to-market accounting. For the year ended December 31, 2008, we had $11.4 million in net gains settled or accounted for using mark-to-market accounting.
 
At December 31, 2010, we had open commodity derivative instruments consisting of crude oil futures and finished product price swaps on a net 1,023,000 barrels to protect the value of certain crude oil, finished product, and blendstock inventories for the first quarter of 2011. These open instruments had total unrealized net losses at December 31, 2010 of approximately $1.2 million. At December 31, 2009, we had open commodity derivative instruments consisting of crude oil futures and finished product price swaps on a net 268,000 barrels to protect the value of certain crude oil, finished product, and blendstock inventories for the first quarter of 2010. These open instruments had total unrealized net losses at December 31, 2009 of approximately $1.5 million. At December 31, 2008, we had open commodity derivative instruments consisting of finished product price swaps on a net 20,000 barrels to protect the value of certain gasoline blendstock inventories for the first quarter of 2009. We did not record an unrealized gain or loss on these open positions since the fair value equaled the trade price on these swaps at December 31, 2008.
 
During the three years ended December 31, 2010, we did not have any commodity derivative instruments that were designated or accounted for as hedges.


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Interest Rate Risk
 
As of December 31, 2010, $616.8 million of our outstanding debt, excluding unamortized discount, was at floating interest rates based on LIBOR and prime rates. An increase in these base rates of 1% would increase our interest expense by $6.2 million per year.


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Management’s Report on Internal Control Over Financial Reporting
 
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
 
  •  Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
 
  •  Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
 
  •  Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. Based on its assessment, the Company’s management believes that, as of December 31, 2010, the Company’s internal control over financial reporting is effective based on those criteria.
 
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 72 of this annual report.


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
 
We have audited the internal control over financial reporting of Western Refining, Inc. as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Management Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010 of the Company and our report dated March 7, 2011 expressed an unqualified opinion on those financial statements.
 
/s/  Deloitte & Touche LLP
 
Phoenix, AZ
March 7, 2011


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders of
Western Refining, Inc.
El Paso, Texas
 
We have audited the accompanying consolidated balance sheets of Western Refining, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
 
/s/ Deloitte & Touche LLP
 
Phoenix, AZ
March 7, 2011


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WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
 
                 
    As of December 31,  
    2010     2009  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 59,912     $ 74,890  
Accounts receivable, principally trade, net of a reserve for doubtful accounts of $3,896 and $1,571, respectively
    283,897       337,559  
Inventories
    365,673       422,753  
Prepaid expenses
    71,935       29,216  
Other current assets
    44,286       79,740  
                 
Total current assets
    825,703       944,158  
Property, plant, and equipment, net
    1,688,154       1,767,900  
Intangible assets, net
    59,945       61,693  
Other assets, net
    54,344       50,903  
                 
Total assets
  $ 2,628,146     $ 2,824,654  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 308,646     $ 405,684  
Accrued liabilities
    122,378       118,569  
Current deferred income tax liability, net
    58,929       45,651  
Current portion of long-term debt
    63,000       63,000  
                 
Total current liabilities
    552,953       632,904  
                 
Long-term liabilities:
               
Long-term debt, less current portion
    1,006,531       1,053,664  
Deferred income tax liability, net
    361,292       391,348  
Environmental, postretirement, and other liabilities
    31,777       58,286  
                 
Total long-term liabilities
    1,399,600       1,503,298  
                 
Commitments and contingencies (Note 21)
               
Stockholders’ equity:
               
Common stock, par value $0.01, 240,000,000 shares authorized; 89,025,010 and 88,688,717 shares issued, respectively
    890       887  
Preferred stock, par value $0.01, 10,000,000 shares authorized; no shares issued and outstanding
           
Additional paid-in capital
    588,215       583,458  
Retained earnings
    109,871       126,920  
Accumulated other comprehensive loss, net of tax
    (1,940 )     (1,370 )
Treasury stock, 698,006 shares, respectively, at cost
    (21,443 )     (21,443 )
                 
Total stockholders’ equity
    675,593       688,452  
                 
Total liabilities and stockholders’ equity
  $ 2,628,146     $ 2,824,654  
                 
 
The accompanying notes are an integral part of these financial statements.


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WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Net sales
  $ 7,965,053     $ 6,807,368     $ 10,725,581  
Operating costs and expenses:
                       
Cost of products sold (exclusive of depreciation and amortization)
    7,155,967       5,944,128       9,735,500  
Direct operating expenses (exclusive of depreciation and amortization)
    444,531       486,164       532,325  
Selling, general, and administrative expenses
    84,175       109,697       115,913  
Goodwill impairment losses
          299,552        
Other impairment losses
    13,038       52,788        
Maintenance turnaround expense
    23,286       8,088       28,936  
Depreciation and amortization
    138,621       145,981       113,611  
                         
Total operating costs and expenses
    7,859,618       7,046,398       10,526,285  
                         
Operating income (loss)
    105,435       (239,030 )     199,296  
Other income (expense):
                       
Interest income
    441       248       1,830  
Interest expense and other financing costs
    (146,549 )     (121,321 )     (102,202 )
Amortization of loan fees
    (9,739 )     (6,870 )     (4,789 )
Write-off of unamortized loan fees
          (9,047 )     (10,890 )
Other income (expense), net
    7,286       (15,184 )     1,176  
                         
Income (loss) before income taxes
    (43,126 )     (391,204 )     84,421  
Provision for income taxes
    26,077       40,583       (20,224 )
                         
Net income (loss)
  $ (17,049 )   $ (350,621 )   $ 64,197  
                         
Net earnings (loss) per share:
                       
Basic
  $ (0.19 )   $ (4.43 )   $ 0.94  
Diluted
  $ (0.19 )   $ (4.43 )   $ 0.94  
Weighted average common shares outstanding:
                       
Basic
    88,204       79,163       67,715  
Diluted
    88,204       79,163       67,715  
 
The accompanying notes are an integral part of these consolidated financial statements.


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WESTERN REFINING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY
(In thousands, except share data)
 
                                                                 
                            Accumulated
                   
    Common Stock           Other
                   
                Additional
          Comprehensive
                   
    Shares
    Par
    Paid-In
    Retained
    Loss,
    Treasury Stock        
    Issued     Value     Capital     Earnings     Net of Tax     Shares     Cost     Total  
 
Balance at December 31, 2007
    68,105,132     $ 679     $ 366,071     $ 417,439     $ (8,056 )     (566,235 )   $ (19,648 )   $ 756,485  
Stock-based compensation
                7,711                               7,711  
Restricted stock vesting
    321,862       5       (5 )                              
Tax deficiency from stock-based compensation
                (659 )                             (659 )
Cash dividend declared
                      (4,099 )                       (4,099 )
Net income
                      64,197                         64,197  
Other comprehensive loss, net of tax benefit of $6,910
                            (10,950 )                 (10,950 )
Treasury stock, at cost
                                  (80,668 )     (1,196 )     (1,196 )
                                                                 
Balance at December 31, 2008
    68,426,994       684       373,118       477,537       (19,006 )     (646,903 )     (20,844 )     811,489  
Public offering of common stock
    20,000,000       200       170,242                               170,442  
Equity component of convertible notes issuance
                36,281                               36,281  
Stock-based compensation
                4,697       4                         4,701  
Restricted stock vesting
    261,723       3       (3 )                              
Tax deficiency from stock-based compensation
                (877 )                             (877 )
Net loss